8-i

CHAPTER 8. LIFE-CYCLE COST AND PAYBACK PERIOD ANALYSES

TABLE OF CONTENTS

8.1 INTRODUCTION ........................................................................................................... 8-1

8.1.1 General Approach for Life-Cycle Cost and Payback Period Analyses ........................... 8-1

8.1.2 The Baseline Scenario...................................................................................................... 8-2

8.1.3 Total Owning Cost ........................................................................................................... 8-2

8.2 LIFE-CYCLE COST METHOD ..................................................................................... 8-3

8.2.1 Definition ......................................................................................................................... 8-3

8.2.2 Life-Cycle Cost Spreadsheet Key Steps .......................................................................... 8-3

8.2.2.2 Step 1: Select A & B ..................................................................................... 8-5

8.2.2.3 Step 2: Select Designs That Meet a Chosen Candidate Standard Level ....... 8-5

8.2.2.4 Step 3: Load and Price Profile ...................................................................... 8-6

8.2.2.5 Step 4: Calculate Cost of Losses ................................................................... 8-6

8.2.2.6 Step 5: Project Losses and Costs into the Future .......................................... 8-7

8.2.2.7 Step 6: Select Discount Rate ......................................................................... 8-7

8.2.2.8 Step 7: Calculate Present Value of Future Cost of Losses............................ 8-7

8.2.2.9 Step 8: Results Reported ............................................................................... 8-7

8.2.2.10 Step 9: Results of Sample of Transformers .................................................. 8-7

8.2.2.11 Repeat Process ............................................................................................... 8-7

8.3 INPUTS TO LIFE-CYCLE COST ANALYSIS ............................................................. 8-8

8.3.1 A and B Transformer Selection Parameters..................................................................... 8-8

8.3.1.1 A and B Parameter Selection for Liquid-Immersed Transformers ................ 8-9

8.3.1.2 A and B Parameter Selection for Dry-Type Transformers .......................... 8-11

8.3.2 Database of Transformer Designs .................................................................................. 8-13

8.3.3 Markup and Installation Costs ....................................................................................... 8-13

8.3.4 Transformer Loading ..................................................................................................... 8-13

8.3.5 Electricity Price Analysis ............................................................................................... 8-14

8.3.5.1 Hourly Marginal Electricity Price Model for Liquid-Immersed 

Transformers ................................................................................................ 8-14

8.3.5.2 Monthly Marginal Electricity Price Model for Dry-Type Transformers ..... 8-18

8.3.6 Load Growth Trends ...................................................................................................... 8-19

8.3.7 Electricity Cost and Price Trends .................................................................................. 8-19

8.3.8 Discount Rate ................................................................................................................. 8-20

8.3.9 Effective Date of Standard ............................................................................................. 8-25

8.3.10 Transformer Service Life ............................................................................................... 8-25

8.3.11 Maintenance Costs ......................................................................................................... 8-25

8.3.12 Power Factor .................................................................................................................. 8-25

8.3.13 Default Scenario............................................................................................................. 8-26

8.4 LIFE-CYCLE COST RESULTS ................................................................................... 8-26

8.4.2 Design Line 1 Results .................................................................................................... 8-29

8.4.3 Design Line 2 Results .................................................................................................... 8-30

8.4.4 Design Line 3 Results .................................................................................................... 8-30

8.4.5 Design Line 4 Results .................................................................................................... 8-31
8-ii

8.4.6 Design Line 5 Results .................................................................................................... 8-31

8.4.7 Design Line 6 Results .................................................................................................... 8-32

8.4.8 Design Line 7 Results .................................................................................................... 8-32

8.4.9 Design Line 8 Results .................................................................................................... 8-32

8.4.10 Design Line 9 Results .................................................................................................... 8-33

8.4.11 Design Line 10 Results .................................................................................................. 8-33

8.4.12 Design Line 11 Results .................................................................................................. 8-34

8.4.13 Design Line 12 Results .................................................................................................. 8-34

8.4.14 Design Line 13 Results .................................................................................................. 8-35

8.5 LIFE-CYCLE COST SENSITIVITY ANALYSIS ....................................................... 8-35

8.5.1 Design Line 1 Summary Sensitivity Results ................................................................. 8-36

8.5.2 Design Line 7 Summary Sensitivity Results ................................................................. 8-38

8.5.3 Design Line 13 Summary Sensitivity Results ............................................................... 8-39

8.6 PAYBACK PERIOD ..................................................................................................... 8-40

8.6.1 Payback Period............................................................................................................... 8-41

8.6.2 Inputs.............................................................................................................................. 8-41

8.6.3 Baseline Scenario Complications .................................................................................. 8-42

8.6.4 Payback Period Results .................................................................................................. 8-43

8.6.5 Design Line 1 Results .................................................................................................... 8-44

8.6.6 Design Line 2 Results .................................................................................................... 8-45

8.6.7 Design Line 3 Results .................................................................................................... 8-46

8.6.8 Design Line 4 Results .................................................................................................... 8-46

8.6.9 Design Line 5 Results .................................................................................................... 8-47

8.6.10 Design Line 6 Results .................................................................................................... 8-48

8.6.11 Design Line 7 Results .................................................................................................... 8-48

8.6.12 Design Line 8 Results .................................................................................................... 8-49

8.6.13 Design Line 9 Results .................................................................................................... 8-50

8.6.14 Design Line 10 Results .................................................................................................. 8-50

8.6.15 Design Line 11 Results .................................................................................................. 8-51

8.6.16 Design Line 12 Results .................................................................................................. 8-52

8.6.17 Design Line 13 Results .................................................................................................. 8-52

8.7 REBUTTABLE PRESUMPTION ................................................................................. 8-53

LIST OF TABLES

Table 8.3.1 A Parameter Model and Historical Data ............................................................ 8-10

Table 8.3.2 A and B Parameter Evaluation Scenarios .......................................................... 8-13

Table 8.3.3 Transmission and Distribution Loss Factors...................................................... 8-15

Table 8.3.4 Generation Capacity Costs ................................................................................. 8-16

Table 8.3.5 Capacity Market Auction Results ...................................................................... 8-17

Table 8.3.6 Average Seasonal Marginal Energy and Demand Prices By Census 

Division (2010$) ................................................................................................ 8-19

Table 8.3.7 Typical Owners of Different Types of Transformers ........................................ 8-22

Table 8.3.8 Variables Used to Estimate Company Discount Rates ...................................... 8-23
8-iii

Table 8.3.9 Real Discount Rates by Transformer Ownership Category ............................... 8-23

Table 8.3.10 Transformer Ownership by Design Line ........................................................... 8-24

Table 8.4.1 Candidate Standard Levels Evaluated For Each Design Line ........................... 8-27

Table 8.4.2 Summary Life-Cycle Cost Results for Design Line 1 Representative Unit ...... 8-29

Table 8.4.3 Summary Life-Cycle Cost Results for Design Line 2 Representative Unit ...... 8-30

Table 8.4.4 Summary Life-Cycle Cost Results for Design Line 3 Representative Unit ...... 8-30

Table 8.4.5 Summary Life-Cycle Cost Results for Design Line 4 Representative Unit ...... 8-31

Table 8.4.6 Summary Life-Cycle Cost Results for Design Line 5 Representative Unit ...... 8-31

Table 8.4.7 Summary Life-Cycle Cost Results for Design Line 6 Representative Unit ...... 8-32

Table 8.4.8 Summary Life-Cycle Cost Results for Design Line 7 Representative Unit ...... 8-32

Table 8.4.9 Summary Life-Cycle Cost Results for Design Line 8 Representative Unit ...... 8-33

Table 8.4.10 Summary Life-Cycle Cost Results for Design Line 9 Representative Unit ...... 8-33

Table 8.4.11 Summary Life-Cycle Cost Results for Design Line 10 Representative Unit .... 8-34

Table 8.4.12 Summary Life-Cycle Cost Results for Design Line 11 Representative Unit .... 8-34

Table 8.4.13 Summary Life-Cycle Cost Results for Design Line 12 Representative Unit .... 8-35

Table 8.4.14 Summary Life-Cycle Cost Results for Design Line 13 Representative Unit .... 8-35

Table 8.5.1 Savings (2010$), Summary Table for Design Line 1 Representative Unit ....... 8-37

Table 8.5.2 Savings (2010$), Summary Table for Design Line 7 Representative Unit ....... 8-38

Table 8.5.3 LCC Savings (2010$), Summary Table for Design Line 13 ............................. 8-40

Table 8.6.1 Possible ΔFC and ΔOC Combinations, for Payback Period Analysis ............... 8-43

Table 8.6.2 Summary of Payback Period Results for Design Line 1 Representative 

Unit .................................................................................................................... 8-45

Table 8.6.3 Summary of Payback Period Results for Design Line 2 Representative 

Unit .................................................................................................................... 8-45

Table 8.6.4 Summary of Payback Period Results for Design Line 3 Representative 

Unit .................................................................................................................... 8-46

Table 8.6.5 Summary of Payback Period Results for Design Line 4 Representative 

Unit .................................................................................................................... 8-47

Table 8.6.6 Summary of Payback Period Results for Design Line 5 Representative 

Unit .................................................................................................................... 8-47

Table 8.6.7 Summary of Payback Period Results for Design Line 6 Representative 

Unit .................................................................................................................... 8-48

Table 8.6.8 Summary of Payback Period Results for Design Line 7 Representative 

Unit .................................................................................................................... 8-49

Table 8.6.9 Summary of Payback Period Results for Design Line 8 Representative 

Unit .................................................................................................................... 8-49

Table 8.6.10 Summary of Payback Period Results for Design Line 9 Representative 

Unit .................................................................................................................... 8-50

Table 8.6.11 Summary of Payback Period Results for Design Line 10 Representative 

Unit .................................................................................................................... 8-51

Table 8.6.12 Summary of Payback Period Results for Design Line 11 Representative 

Unit .................................................................................................................... 8-51

Table 8.6.13 Summary of Payback Period Results for Design Line 12 Representative 

Unit .................................................................................................................... 8-52

Table 8.6.14 Summary of Payback Period Results for Design Line 13 Representative 

Unit .................................................................................................................... 8-53
8-iv

Table 8.7.1 Average Transformer Efficiency ....................................................................... 8-54

Table 8.7.2 Average Transformer Installed Cost .................................................................. 8-55

Table 8.7.3 First Year Operating Cost for Rebuttable Presumption, Based on DOE 

Test ..................................................................................................................... 8-55

Table 8.7.4 Rebuttable Payback for Rebuttable Presumption Period ................................... 8-56

LIST OF FIGURE

Figure 8.2.1 Transformer Life-Cycle Cost Spreadsheet Model Flowchart .............................. 8-4

Figure 8.3.1 Cumulative Distribution of Historical A Parameter and A Parameter 

Model ................................................................................................................. 8-10

Figure 8.3.2 Distributions of Load Loss (B) Values versus No Load Loss (A) Values 

for Liquid-Immersed Transformers ................................................................... 8-11

Figure 8.3.3 AEO 2010 Electricity Price Forecasts ............................................................... 8-20

Figure 8.4.2 Design Load Losses (LL) versus No-Load Losses (NL) in the Basecase 

and CSL 1 for Design Line 1 ............................................................................. 8-28

Figure 8.4.3 Distribution of LCC Savings Results for DL2, CSL 2 ...................................... 8-29

Figure 8.5.1 Average LCC Savings (2010$) by Scenario for Design Line 1 ......................... 8-37

Figure 8.5.2 Average LCC Savings (2010$) by Scenario for Design Line 7 ......................... 8-39

Figure 8.5.3 Average LCC Savings (2010$) by Scenario for Design Line 13 ....................... 8-40

Figure 8.6.1 Distribution of Payback Period Results for DL 2, CSL 2 .................................. 8-44
8-1

CHAPTER 8. LIFE-CYCLE COST AND PAYBACK PERIOD ANALYSES

8.1 INTRODUCTION

This chapter of the technical support document (TSD) presents DOE’s life-cycle cost 

(LCC) and payback period (PBP) analyses. It describes the method DOE used for analyzing the 

economic impacts of possible standards on consumers. The effect of standards on consumers 

includes a change in operating expense (usually decreased) and a change in purchase price 

(usually increased). The LCC and PBP analyses produce two basic outputs to describe the effect 

of standards on consumers: 

• LCC is the total (discounted) cost that a consumer pays over the lifetime of the 

equipment, including purchase price, installation cost, and operating expenses. 

• PBP measures the amount of time it takes consumers to recover the estimated higher 

purchase expense of more energy efficient equipment through lower operating costs. 

This chapter presents inputs and results for the LCC and PBP analyses, as well as key 

variables, current assumptions, and computational equations. DOE performed the calculations 

discussed here using a series of Microsoft Excel spreadsheets, which are accessible on DOE's 

website (http://www.eere.energy.gov/buildings/appliance_standards/commercial/

distribution_transformers.html). Section 8.8 of this document contains details and instructions 

for using the spreadsheets. There are five appendices to this chapter: 1) Appendix 8C presents a 

complete set of results; 2) Appendix 8B discusses uncertainty and variability;3) Appendix 8D 

contains a complete set of sensitivity results for design lines 1, 7 and 13. 

8.1.1 General Approach for Life-Cycle Cost and Payback Period Analyses 

Recognizing that each transformer customer is unique, DOE calculated the LCC and PBP 

for a representative sample (a distribution) of individual transformers. In this manner, DOE’s 

analysis explicitly recognized that there is both variability and uncertainty in its inputs. DOE 

used Monte Carlo simulations to model the distributions of inputs. 

The Monte Carlo process statistically captures input variability and distribution without 

testing all possible input combinations. The results are expressed as the number of transformers 

experiencing economic impacts of varying magnitudes. DOE developed the LCC model using 

Excel spreadsheets combined with Crystal Ball, a commercially available add-in program. A 

detailed explanation of the Monte Carlo simulation process and the use of probability 

distributions in this analysis are contained in Appendix 8B. 

 The LCC results are displayed as distributions of impacts compared to the baseline 

conditions. DOE presents tabular results at the end of this chapter; they are based on 10,000 

samples per Monte Carlo simulation run
8-2

DOE developed two approaches for the LCC calculations: one for liquid-immersed 

transformers and one for medium-voltage, dry-type transformers. Because the large majority of 

liquid-immersed transformer owners are utilities, the liquid-immersed LCC calculations used 

utility marginal costs and distribution markups that do not include a wholesaler and contractor 

markup. In contrast, because the majority of dry-type transformer owners are commercial and 

industrial enterprises, DOE used monthly marginal electricity costs and complete distribution 

markups for the dry-type transformer LCC calculation. For simplicity, DOE used only one type 

of LCC calculation for each design line of transformer, based on the majority owner type of that 

category. 

8.1.2 The Baseline Scenario

In developing appliance standards, DOE has traditionally used an existing standard level 

as a baseline from which it calculates the impact of any candidate standard level. Because 

distribution transformers are not currently subject to a national energy efficiency standard, DOE 

developed an alternative approach to determine an appropriate baseline against which to compare 

various candidate standard levels. That alternative approach focused on the mix of selection 

criteria customers are known to use when purchasing transformers. Those criteria include first 

costs, as well as what is known in the transformer industry as total owning cost (TOC), used by 

some customers as an alternative criterion to first costs. The TOC method combines first costs 

with the cost of losses. Purchasers of distribution transformers, especially in the utility sector, 

have long used the TOC method to determine which transformers to purchase.1,2 

To establish the LCC baseline scenario, DOE used distributions of efficiencies and an 

estimated percent of transformers currently being purchased using the TOC method. That 

scenario represents the range of transformer costs and efficiencies that transformer purchasers 

would likely experience without national energy efficiency standards in place. 

8.1.3 Total Owning Cost 

The utility industry developed TOC evaluation as an easy-to-use tool to reflect the unique 

financial environment faced by each transformer purchaser. To express variation in such factors 

as the cost of electric energy, and capacity and financing costs, the utility industry developed a 

range of evaluation factors, called A and B values, to use in their calculations. A and B are the 

equivalent first costs of the no-load and load losses (in $/watt), respectively. No-load losses 

refer to the core losses that are roughly constant once the transformer is energized; load losses 

are the coil losses that vary roughly with the square of the load on the transformer. 

The TOC transformer purchasers (those using the TOC method to determine which units 

to buy) assign an economic value to transformer losses: A and B parameters. Then they add 

these costs to the first cost of acquiring the transformer, to derive TOC. The equation for 

calculating transformer TOC is:

TOC = FC + (A × NLL) + (B × LL)

where:
8-3

FC = first cost of acquiring the transformer, including purchase price and 

installation cost (2006$), 

A = the no-load loss valuation parameter in dollars per watt ($/W), 

NLL = the no-load loss at nameplate load (W),

B = the load loss valuation parameter ($/W), and 

LL = the load loss at nameplate load (W).

 Throughout the LCC analysis, DOE expresses monetary values in units of year 2010 real 

dollars (2010$).

8.2 LIFE-CYCLE COST METHOD

8.2.1 Definition

The basis for both the LCC analysis and the LCC spreadsheet model is the LCC equation. 

The LCC equation reflects both the first costs of a transformer and the present value of the 

operating costs over the service life of the transformer.

The LCC equation is:

LCC = FC + ∑ �

OCn

(1+Drate) � n� Lifetime

1

where:

FC = the first cost (2010$),

n = the index for the year of operation (yr), 

Lifetime = the service life of the transformer,

OCn

Drate = the discount rate applied to the calculation (%). 

= the operating cost in year n, including the value of the losses and 

maintenance costs (2010$/yr), and 

8.2.2 Life-Cycle Cost Spreadsheet Key Steps

While the LCC is a simple equation, DOE's LCC spreadsheet model takes into account 

the dynamic nature of a variety of inputs over the service life of a transformer. A simplified 

flowchart (Figure 8.2.1) illustrates the key steps implemented in the LCC spreadsheet: the main 

inputs, the key computational steps, and the important outputs. The LCC spreadsheet is 

available as an Excel file on the DOE website at 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformer

s.html. 
8-4

Figure 8.2.1 Transformer Life-Cycle Cost Spreadsheet Model 

Flowchart

Sections 8.2.2.1 through 8.2.2.11 describe the computational flow of the LCC model as 

shown in the flowchart. Following this explanation of the analytical steps in the model, this 

chapter presents the specific inputs that DOE developed and then used in the LCC model for this 

rulemaking. Next, the chapter presents the results of the LCC model runs for the various design 

lines, and the key sensitivities to those results.
8-5

The LCC process is a means of determining the financial impact resulting from the 

imposition of energy efficiency standards for distribution transformers, from the perspective of 

the consumer, or owner, of the transformer. Several types of information are necessary for this 

calculation: the first costs of transformers with and without standards, the operating costs of the 

transformers with and without standards, the year the standard is to become effective, and the 

lifetime of transformers. For ease of comparison, DOE presents all costs in present values, 

which requires using discount rates. The section on LCC inputs (section 8.3) explains in more 

detail DOE’s methods for determining these inputs.

8.2.2.2 Step 1: Select A & B

Step 1: Select customer choice A and B parameters from the choices on the “A & B 

Dist” worksheet. The purpose of this step is to establish the current purchasing decision 

environment. For liquid-immersed transformers assumed that 25 percent are purchased based on 

lowest first cost and 75 percent are purchased using TOC evaluation.3

Commercial and industrial (C&I) entities can also apply an A- and B-based evaluation 

process for dry-type transformer purchase evaluation. While the analytic process for 

determining A and B values used by C&I purchasers is different from that used by electric 

utilities, the fundamental meanings of A and B are the same for both groups of transformer 

purchasers. 

The LCC spreadsheet simulates different transformer purchase evaluation scenarios with 

two different A and B models. All liquid-immersed transformer design lines use the same 

model, while dry-type design lines use a different implementation. The specific inputs used in 

these two scenarios are shown in section 8.3 of this TSD chapter, as well as in the “A & B Dist” 

worksheet of the liquid-immersed and “Demand and Usage” worksheet of the dry-type LCC 

spreadsheets. These scenarios can be selected using the “Transformer Customer A’s and B’s” 

pull-down menu on the “Summary” worksheet. Step 2 below explains the application of these A 

& B distributions when actual transformer designs are selected. 

8.2.2.3 Step 2: Select Designs That Meet a Chosen Candidate Standard Level

Step 2: Select designs and a candidate standard level. The purpose of this step is to select 

a candidate standard level and its associated transformer designs to evaluate with the LCC 

spreadsheet. DOE developed up to seven candidate standard levels for each DL based on 

information obtained from the engineering analysis. The engineering analysis yielded a costefficiency relationship in the form of manufacturer selling prices, no-load losses, and load losses 

for a wide range of realistic transformer designs. This set of data provided the LCC model with 

a distribution of transformer design choices. (See the “Design Table” worksheet, a condensed 

version of the engineering analysis output.) After the user chooses a candidate standard level, 

the spreadsheet selects from its database of designs the subset of designs that satisfy the selected 

candidate standard level and another set of designs that satisfy the baseline scenario.

In addition to the economic value of losses, other factors may affect design selection. 

DOE accounted for such factors by adding a random cost factor to the transformer’s first costs. 
8-6

Using this factor, DOE captured the range of typical real-world cost variation in the first cost of 

the transformer. DOE modeled this random cost factor as a uniformly distributed random 

number that can either raise or lower the first cost of the transformer by up to 15 percent. The 

spreadsheet selects the transformer design that has the lowest TOC (including the random cost 

factor) for the customer. For each iteration cycle, a design is chosen based on A and B 

distributions from Step 1. 

Step 2a: Calculate markup and installation costs. For liquid-immersed transformers, 

which are typically purchased directly by utilities from manufacturer representatives, DOE 

considered the transformer purchase price to be the manufacturer selling price plus a distributor 

markup and sales tax. It added installation costs separately. For dry-type transformers, the 

distribution channel includes various intermediaries who add their own costs to the manufacturer 

selling price. These costs include a manufacturer markup, distribution markup, contractor 

markup, installation costs, and sales tax. 

Key inputs for this step include markup and installation costs. DOE presents its specific 

values for these inputs in Chapter 6. 

8.2.2.4 Step 3: Load and Price Profile 

Step 3: The spreadsheet model dynamically selects a sample transformer load profile 

from distributions derived from available data. To estimate the impact of transformer losses on 

C&I companies’ electricity bills, DOE modeled the relationship between monthly transformer 

load characteristics and customer demand and usage. DOE derived distributions of load 

parameters from available hourly load data. For liquid-immersed transformers, DOE developed 

an hourly transformer load simulation model to capture the dynamics and economics of 

transformer loads.

The load profiles and characteristics are provided in the “Price Load Model” worksheet 

of the LCC spreadsheet for liquid-immersed transformers and in the “Demand & Usage” 

worksheet of the LCC spreadsheet for dry-type transformers.

For the cost of electricity, DOE used the marginal cost of electricity for liquid-immersed 

transformers. For dry-type transformers, it developed a method to calculate customer monthly 

bills. For both transformer types, DOE calculated the total cost of electricity both with and 

without transformer losses and took the difference to calculate the incremental electricity costs. 

section 8.3.5 provides a detailed discussion of the electricity price analysis. 

8.2.2.5 Step 4: Calculate Cost of Losses 

Step 4: The spreadsheet model calculates the cost of losses by estimating the incremental 

impacts of no-load and load losses from the loss coefficients of the design, the monthly customer 

load characteristics (demand and usage), and the cost of electricity. In this step, the spreadsheet 

combines the no-load losses, load losses, and electricity price information for each transformer in 

the baseline scenario and in the standards scenario. Subsequent steps project the costs of losses 

into the future and then convert them back to present values. 
8-7

8.2.2.6 Step 5: Project Losses and Costs into the Future

Step 5: The spreadsheet model projects losses and costs into the future, based on load 

growth assumptions and a forecast of future changes in electricity price. Spreadsheet users can 

select different load growth and future electricity price scenarios. The model applies the selected 

options for load growth and price trends to the initial cost of losses that were calculated in Step 

4. Step 5 results in a projection of those losses and costs into the future. DOE presents its 

specific load growth and electricity price trends in the LCC inputs section (section 8.3) of this 

chapter.

8.2.2.7 Step 6: Select Discount Rate

Step 6: To discount the future stream of costs into a present value, the spreadsheet model 

selects a discount rate from the discount rate distribution. The LCC spreadsheet selects a 

discount rate from a weighted sample of discount rate inputs derived from financing costs of 

transformer purchasers. DOE presents its specific discount rates in the LCC inputs section 

(section 8.3) of this chapter. 

8.2.2.8 Step 7: Calculate Present Value of Future Cost of Losses

Step 7: The spreadsheet model calculates the present value of future operating costs and 

losses and the present worth per watt of no-load and load losses. This step applies the discount 

rate selected in Step 6 to the future costs of losses from Step 5 to produce a single, presentvalued number. In addition to the costs from Step 5 above, the calculation uses as inputs the 

effective date of the standard, the transformer lifetime, maintenance costs, and a power factor.

8.2.2.9 Step 8: Results Reported

Step 8: The spreadsheet model records the LCC, LCC savings, payback period, and other 

results for inclusion in the distribution of results. 

8.2.2.10 Step 9: Results of Sample of Transformers

Step 9: The spreadsheet model repeats the calculation until reaching the specified 

maximum number of iterations. When applying a Monte Carlo simulation process, the model 

performs a user-defined number of iterations and reports the results as distributions. Based on 

DOE’s experience with expressing results of prior rulemakings as distributions, 10,000 iterations 

in a Monte Carlo simulation capture sufficient variability.

8.2.2.11 Repeat Process

The specific number of iterations required for the Monte Carlo simulation is implemented 

through the <Repeat Process> decision box. When the desired number of iterations has been 

reached, the model ends the simulation process and generates result reports. 
8-8

8.3 INPUTS TO LIFE-CYCLE COST ANALYSIS

This section presents the specific LCC inputs used in the spreadsheet model and provides 

definitions and data sources for each component. This section also elaborates on how the LCC 

spreadsheets apply certain user-chosen inputs to the LCC model. The specific inputs to the 

model, in the order in which they appear on the left-hand side of the LCC flowchart (Figure 

8.2.1), are:

• A and B transformer selection parameters and usage rates

• Database of transformer designs

• Markup and installation costs 

• Transformer loading

• Electricity costs and prices

• Load growth trends 

• Electricity cost and price trends

• Discount rate 

• Effective date of standard

• Transformer service life

• Maintenance costs

• Power factor

8.3.1 A and B Transformer Selection Parameters

The A and B transformer selection parameters that DOE used in the formal TOC 

calculation characterize the value that transformer purchasers place on reducing no-load and load 

losses in transformers. This is because the A and B parameters express a measure of the 

economic value of loss reduction in terms of dollars per watt of reduced losses. The main 

assumption implicit in using A and B values to represent customer transformer choice decisions 

is that the value of loss reduction is proportional to the amount by which losses are reduced. 

Given this wider applicability of the TOC formulation to the expression of loss valuations, DOE 

used A and B parameters to formulate a transformer customer choice model. 

To represent the potential range of purchaser valuation of losses, DOE developed three 

customer choice scenarios for each LCC calculation. The difference among the three scenarios 

is the fraction of purchasers who place a value on reducing transformer losses. Those who place 

a value on reducing such losses are described as evaluators, while those who do not consider 

transformer losses during a purchase are termed non-evaluators. The scenario representing nonevaluation for all purchases has 0 percent evaluators, while the scenario representing evaluation 

for all purchases has 100 percent evaluators. 

For liquid-immersed transformers, many purchases are evaluated, so DOE’s default 

scenario is an evaluation rate of 75 percent, which is approximately consistent with data 

provided by NEMA3 regarding the fraction of transformers that are TP 1-compliant. As the 

voluntary industry standard for transformer efficiency, TP 1 has its compliance tracked by 

NEMA. DOE extrapolated these TP 1 compliance data to an estimated distribution of market 

efficiencies. For low-voltage, dry-type transformers, as few purchasers consider transformer 
8-9

losses as part of the purchase decision, DOE assumed a default evaluation rate of 10 percent. For 

medium-voltage, dry-type transformers, DOE assumed 50 percent evaluators for small-capacity 

transformers—design line (DL) 9 and DL 11—and 80 percent for large-capacity transformers—

DLs 10, 12, and 13. These default scenarios produced results roughly consistent with NEMA 

data regarding the fraction of transformers compliant with TP 1 in the current market. 

DOE used the 0 percent and 100 percent evaluation scenarios to test the LCC sensitivity 

to changes in the percentage of transformers purchased using evaluation. It estimated the mean 

value of A for evaluators from values from public transformer purchase bids available on the 

Internet.3,4,5,6,7,8,9,10,11 Then, recognizing that there is substantial variability in the value that 

transformer purchasers may place on reducing losses, DOE created separate statistical models for 

the A and B parameters for liquid-immersed and dry-type transformers.

For each value of A that a transformer purchaser may have, there is a range of possible B 

values that are consistent with the particular A parameter. (B parameters relate to the value 

associated with the load losses.) In general, the ratio of B to A is a measure of the relative 

importance of load losses and no-load losses. For a transformer that is constantly loaded at 100 

percent of rated capacity, the value of B and A should be the same, since both load and no-load 

losses will always be at their rated values. Load losses increase with the square of the loading, 

and transformer mean loadings are almost always below 100 percent. Therefore, in practice, B is 

always less than A, and is approximately equal to A times the square of the expected loading 

(when peak loads are not considered). 

8.3.1.1 A and B Parameter Selection for Liquid-Immersed Transformers

DOE collected A and B parameters from transformer purchase bids available on the 

Internet and combined these with the sample used in the previous final rule3. As the bid 

documents were published in different years, in order to evaluate the data, DOE normalized the 

A and B parameters to 2010$ using the BEA’s Producer Price Index for Power Generation.12 

 A Parameter. To model the distribution of A values in the data, DOE developed a 

Piecewise linear fit to the empirical distribution. Figure 8.3.1 shows the cumulative distribution 

function for both the data and the model. 
8-10

Figure 8.3.1 Cumulative Distribution of Historical A Parameter

and A Parameter Model

Table 8.3.1 A Parameter Model and Historical Data

A Parameter 

Midpoint

$/W

Model Cumulative 

Probability

%

Historical Data Cumulative 

Probability

%

2.5 0.20 0.2051

3.5 0.30 0.2821

4.5 0.60 0.5897

5.5 0.70 0.6667

6.5 0.80 0.7949

7.5 0.90 0.9231

8.5 0.95 0.9487

9.5 0.96 0.9487

10.5 0.97 0.9744

11.5 0.98 0.9744

12.5 0.99 1.0000

B Parameter. The data show that there is some dependence of the B parameter value on 

the value of A used by the purchaser, with most of the data points lying in two distinct clusters. 

These clusters represent different ratios of B to A, and like reflect the different technologies used 

to serve base load and peak load. The first cluster, consisting of approximately 40 percent on the 

sample, has a B:A ratio of 0.24, and represents utilities that place relatively low economic value 

on load losses. The second cluster, has a B:A ration of 0.46, and represents utilities that place 

relatively higher economic value on load losses. Figure 8.3.2 illustrates the two clusters. Each 

cluster is modeled as a linear fit plus a random increment. In the LCC model, purchasers are 

assigned to one or the other category of B to A ratio randomly, in the same proportion as is seen 

in the data.

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5

Probability

A Value $/W (2010$)

Cumulative Distribution of A Values

Historical Data

Model
8-11

Figure 8.3.2 Distributions of Load Loss (B) Values versus No 

Load Loss (A) Values for Liquid-Immersed 

Transformers

8.3.1.2 A and B Parameter Selection for Dry-Type Transformers

DOE developed separate A and B parameter models for dry type transformers which are 

owned by C&I building owners. These transformer owners pay for the energy dissipated by the 

transformer at a price specified by their electricity tariff. DOE estimated that 60 percent of drytype transformers go into commercial buildings, while 40 percent go into industrial buildings 13,. 

This distribution is accounted for in the LCC by adjusting the individual building weights. For 

each design line, only buildings whose peak load is larger than the transformer capacity are 

included in the customer sample. 

 A Parameter. DOE used the following equation to convert the customer’s marginal 

electricity prices to the appropriate A value: 

A = HPW × MPEW + HPS × MPES + MW × MPDW + MS × MPDS

FCR � , 

where:

MPEW = the winter marginal energy charge ($/kwh) (see section 8.3.5.1) 

MPDW = the winter marginal demand charge ($/kw) (see section 8.3.5.1) 

MPES = the summer marginal energy charge ($/kwh) (see section 8.3.5.1) 

MPDS = the summer marginal demand charge ($/kw) (see section 8.3.5.1) 

HPW

HP

 = the number of hours in the winter period 

S = the number of hours in the summer period 

y = 0.23x + 0.00

R2 = 0.91

y = 0.45x + 0.02

R2 = 0.61

0

1

2

3

4

5

0 2 4 6 8 10 12 14

Load Losses (B) $/W ( 2010$)

No-load Losses (A) $/W (2010$)

Line 1

Line 2

Linear (Line 1)

Linear (Line 2)
8-12

MW

M

 = the number of months in the winter period, winter is defined as the months 

October through April 

S

FCR = the fixed charge rate, here equal to 0.2

 = the number of months in the summer period, summer defined as the 

months of May through September. 

14

 

B Parameter. The equation for B is similar to that for A, with modifications that account 

for the fact that the load losses depend on the square of the load on the transformer. The 

transformer load loss rate is defined assuming the transformer is fully loaded; in reality the 

transformer is partially loaded most of the time. This is accounted for by the transformer loss 

factor (LSF), equal to the average of the square of the transformer load divided by the square of 

the peak transformer load. The building peak load will be reduced by an amount equal to the 

square of the load on the transformer at the time of the building peak; this is accounted for by the 

transformer peak responsibility factor. The formula for the B parameter is: 

B = LSF(HPW × MPEW + HPS × MPES) + RF(MW × MPDW + MS × MPDS)

FCR � , 

where:

LSF = the transformer energy loss factor, which is equal to the square of the 

transformer RMS load. 

RF = the transformer peak responsibility factor, which is equal to the square of the 

ratio of the transformer load during the hour of the building peak to the peak 

transformer load

For both A and B, the fixed charge rate is used to convert the annual payment required to cover 

load losses to an NPV. 

To summarize, DOE characterized transformer purchases with respect to efficiency in 

terms of two economic valuation parameters. The parameter A expresses the value that a 

customer gives to reducing no-load losses in dollars per watt, while the parameter B expresses 

the value given to reducing load losses at rated load. DOE described purchase behavior in terms 

of evaluators who place a value on reducing losses, and non-evaluators who place no value on 

reducing losses. DOE investigated four scenarios as sensitivities: (1) liquid-immersed, (2) smallcapacity low-voltage dry-type, (3) small-capacity medium-voltage dry-type and (4) largecapacity medium-voltage dry-type. The A and B parameter evaluation rates for the low, medium 

and high sensitivities for each of those scenarios are shown in Table 8.3.2. DOE selected 

evaluation percentages to be consistent with NEMA data regarding the fraction of transformers 

compliant with TP 1 in the current market. For evaluators, DOE used a distribution of A and B 

values to characterize the economic criteria used in the purchase decision.
8-13

Table 8.3.2 A and B Parameter Evaluation Scenarios 

Percentage of Evaluators

Low Medium High

Liquid-immersed 0% 75% 100%

Small-Capacity Low-voltage Dry-type 0% 10% 100%

Small-Capacity Medium-voltage Dry-type 0% 50% 100%

Large-capacity Medium-voltage Dry-type 0% 80% 100%

8.3.2 Database of Transformer Designs 

Establishing a relationship between cost and efficiency is an integral part of the 

rulemaking process. For transformers, DOE derived this relationship from an engineering 

analysis database of selling prices, no-load losses, and load losses for a wide range of realistic 

transformer designs contained in the LCC spreadsheets. DOE used a commercial transformer 

design software company, Optimized Program Service Inc., and its software to create the 

database of designs. The database consists of a wide range of efficiencies and manufacturer 

selling prices (including a predetermined manufacturer markup) to represent the variability of 

designs in the marketplace. The engineering analysis (see Chapter 5) provides more detail on the 

database structure and the method used to generate this database of transformer designs. 

8.3.3 Markup and Installation Costs

Markups, shipping costs, sales tax, and installation costs are the costs associated with 

bringing a manufactured transformer into service as an installed piece of electrical equipment. 

For liquid-immersed transformers, which utilities typically purchase directly from 

manufacturers, DOE considered the transformer purchase price to be the manufacturer selling 

price plus a distributor markup, the shipping cost, and sales tax. DOE added installation costs 

separately. For dry-type transformers, the distribution channel includes various intermediaries 

who add their own costs to the manufacturer selling price. These costs include a manufacturer 

markup, distribution markup, contractor markup, shipping cost, installation costs, and sales tax. 

See Chapter 7 for a detailed discussion of the markup calculations. 

8.3.4 Transformer Loading

To estimate the economic burdens and benefits of efficiency improvements, DOE 

characterized the energy use and losses of the equipment being analyzed, by estimating the loads 

on them. Because the application of distribution transformers varies significantly by type of 

transformer (liquid-immersed or dry-type) and ownership (electric utilities own liquid-immersed 

95 percent of the time, commercial/industrial entities use mainly dry-type), DOE performed two 

separate load analyses to evaluate distribution transformer efficiency: one for liquid-immersed 

transformers and a second for dry-type transformers. Chapter 7 Energy Use and End-Use Load 

Characterization of this TSD describe these two separate load analyses.
8-14

8.3.5 Electricity Price Analysis

This section describes the electricity price analyses DOE used to determine the energy 

portion of the annual operating expenses for distribution transformers. 

DOE performed two types of load analysis to evaluate distribution transformer efficiency. 

The first type of analysis investigated the nature of hourly transformer loads, their correlation 

with the overall utility system load, and their correlation with hourly electricity costs and prices. 

The second type of analysis estimated the impacts of transformer loads and the resultant 

transformer losses on the monthly electricity usage, demand, and electricity bills of C&I 

customers. DOE refers to the two analyses as hourly and monthly analyses, respectively. DOE 

used the hourly analysis for the economic analysis of liquid-immersed transformers, which are 

predominantly owned by utilities whose costs vary by the hour. DOE used the monthly analysis 

to evaluate dry-type transformers, which are typically owned by C&I establishments that receive 

monthly electricity bills. 

8.3.5.1 Hourly Marginal Electricity Price Model for Liquid-Immersed 

Transformers

For liquid-immersed transformers, DOE used marginal electricity prices. Marginal 

electricity prices are the prices experienced by utilities for the last kilowatt-hour (kWh) of 

electricity produced. A utility’s marginal price can be higher or lower than its average price, 

depending on the relationships between capacity, generation, transmission, and distribution costs. 

The general structure of the hourly marginal cost equation divides the costs of electricity into 

capacity components and energy cost components. For each of those cost components DOE 

estimated the economic value for both the no-load losses and load losses. The capacity 

components include generation capacity and transmission capacity. Capacity components also 

include a reserve margin needed to ensure system reliability and factors that account for system 

losses. Energy cost components include a marginal cost of supply that varies by the hour. DOE 

developed two methods to calculate these marginal costs for the set of regions defined in the EIA 

National Energy Modeling System (NEMS) Electricity Market Module (EMM).15. The method 

chosen depends on whether the utility is part of a traditionally regulated system, or part of a 

restructured system with functioning capacity markets. 

 DOE developed two sets of capacity costs to be applied to the two types of losses: 

CCNLL

CC

 = the value of the capacity costs associated with no-load losses, 

LL = the value of the capacity costs associated with load losses.

These terms are defined as follows:

CCNLL = (1 + CM)(βCGFG + CTFT), 

and

CCLL = (1 + CM)(βCGFG + CTFT)∆P. 

Where:
8-15

CM

β = load adjustment factor, which is one plus the estimated system losses, 

 = the reserve capacity margin, 

CG

F

 = the cost in $/kW of building new generation capacity, 

G

C

 = the fixed charge rate used to calculate the annual revenue requirement 

needed to cover an investment in generation capacity.

T

F

 = The overnight cost in $/kW of new transmission capacity, 

T

∆P = the system peak load reduction. 

= the fixed charge rate for transmission investments

DOE calculated the various inputs of this equation as follows: 

Capacity Margin (CM). This is the fraction of extra or reserve capacity needed to ensure 

system reliability per unit of additional capacity requirement. DOE used the industry standard of 

15 percent. 

Loss Adjustment Factor (β). The loss adjustment factor represents the fraction of 

electricity that is dissipated from the electrical system during generation and transmission. It is 

one plus the fractional losses in the system. DOE used a constant average value of 1.08, which 

was based on the regional transmission and distribution loss factors from the NEMS Planning 

Model.3 The regional transmission and distribution loss factors can be found in Table 8.3.2. 

Table 8.3.3 Transmission and Distribution Loss Factors 

EMM 1 2 3 4 5 6 7 8 9 10 11 12 13

β 1.070 1.065 1.072 1.068 1.088 1.080 1.080 1.068 1.068 1.081 1.093 1.093 1.093

Unit Generation Capacity Cost (CG). This is the overnight cost of building new 

generating capacity, provided by NEMS.15

Table 

8.3.3

 These costs do not include financing charges; DOE 

added the cost of financing to the overnight costs assuming a cost of capital of 5 percent. 

 show the no-load loss and load loss capacity rates used for regulated systems. 
8-16

Table 8.3.4 Generation Capacity Costs 

EMM 

Region 

EMM Region 

Name

Load Loss Generation No-load Loss Generation

Technology $/kW-year Technology $/kW-year 

1 ECAR Combined Cycle 158.71 Advanced Coal 560.39

2 ERCOT Combined Cycle 158.71 Advanced Coal 560.39 

3 MAAC Half & Half 359.55 Advanced Coal 560.39 

4 MAIN Half & Half 359.55 Advanced Coal 560.39 

5 MAPP Half & Half 359.55 Advanced Coal 560.39 

6 NY Combined Cycle 158.71 Combined Cycle 158.71 

7 NE Combined Cycle 158.71 Combined Cycle 158.71 

8 FL Combined Cycle 158.71 Advanced Coal 560.39 

9 SERC Half & Half 359.55 Advanced Coal 560.39 

10 SPP Half & Half 359.55 Advanced Coal 560.39 

11 NPP Combined Cycle 158.71 Advanced Coal 560.39 

12 RA Combined Cycle 158.71 Advanced Coal 560.39 

13 CA Combined Cycle 158.71 Advanced Coal 560.39 

 Generation Fixed Charge Rate (FG). This is the fixed charge rate used to calculate the 

annual revenue required to cover investment in generation capacity. DOE used a value of 0.15.3

 Unit Transmission Capacity Cost (CT). This is the overnight cost per unit for an 

increment of new transmission capacity, provided by NEMS15.

 Transmission Fixed Charge Rate (FT). This is used to convert the lump-sum investment 

into an annual revenue requirement. DOE used a value of 0.12.15

 Peak Load Reduction (∆P). The reduction in peak load that results from improved 

transformer efficiency. DOE used a statistical model to estimate this reduction consistent with 

the methodology used to model transformer hourly loads. 

 DOE preformed similar calculations for regions with functioning capacity markets. For 

these regions DOE assumed the value of generation capacity for load losses can be inferred from 

the capacity market results.

CCLL = (1 + CM)(CAP + CTFT)∆P. 

Capacity Market Rate (CAP). DOE collected forward capacity market auction results 

for systems with functioning capacity markets from each region’s independent system operator’s 

websites.16,17,18 These values can be seen in Table 8.3.4. 
8-17

Table 8.3.5 Capacity Market Auction Results

EMM Region ISO

Market Auction Results

Percent of Region Served CAP ($/KW-year)

1 ECAR PJM 30% $63.66 

3 MAAC PJM 100% $64.45 

4 MAIN PJM 20% $63.66 

6 NY NYISO 100% $162.18 

7 NE NEISO 100% $54.00 

9 SERC PJM 5% $63.66 

 DOE developed two sets of energy costs to be applied to the two types of losses: 

ECNLL

EC

 = the value of the capacity costs associated with no-load losses,

LL = the value of the capacity costs associated with load losses.

These terms can be further expressed as:

ECNLL = β ∈NLL ∑ P(h) h , 

and

ECLL = β ∈LL ∑ P(h)e2(h) h . 

Where:

β = load adjustment factor, which is one plus the estimated system losses,

∈NLL = the no-load (constant) loss rate, 

∈LL = the load loss rate, 

P(h) = hourly electricity price, 

e

2

(h) = hourly transformer load. 

Hourly Electricity Price (P(h)). This is the hourly price of electricity. DOE used the 

day-ahead market clearing price for regions with wholesale electricity markets, and system 

lambda values for all other regions. System lambda values are roughly equal to the operating cost 

of the next unit in line for dispatch, and are filed by control area operators under FERC Form 

71419. DOE used the most recent data available for both market prices and system lambdas, from 

the year 2008. 

Hourly Transformer Load (e

2

(h)). The hourly load on the transformer, DOE used a 

statistical model to represent hourly variations in transformer loading and the correlation with 

hourly-varying system electricity prices. The hourly load model is discussed in detail in chapter 

7 of this TSD. 
8-18

No-load Loss Rate (∈NLL). This is the no-load loss rate of the selected transformers. This 

parameter is imported from the database of transformer design options that were developed in the 

engineering analysis.

Load Loss Rate (∈LL). This is the load loss rate of the selected transformers. This 

parameter is imported from the database of transformer design options. The load loss rate is 

estimated while the transformer is fully loaded

8.3.5.2 Monthly Marginal Electricity Price Model for Dry-Type Transformers

For C&I building owners of dry-type transformers, DOE developed average marginal 

electricity prices from a tariff based analysis of marginal energy prices of commercial 

buildings.20,21 . 

 Electricity tariffs for C&I consumers can be very complex, incorporating block rates, 

seasonal rates, demand charges, time-of-use rates. To calculate commercial electricity bills 

requires both the monthly consumption and demand; for utilities with mandatory time-of-use 

(TOU) tariffs consumption and demand data are required for each TOU period. Monthly billing 

data, consisting of electricity consumption, demand, and expenditures, are available for the 

CBECS 1992 and CBECS 1995 survey yearsa

. These monthly data were processed using the 

tariff bill calculation tools20 to provide the corresponding monthly utility bill. DOE used these 

baseline utility bills to calculate average prices. Because the customer bill depends on both 

energy consumption and demand, separate marginal prices are needed to represent the effect of 

varying these two quantities independently. The monthly marginal electricity consumption (or 

demand) price is calculated by decrementing the electricity consumption (or demand) and 

recalculating the bill. DOE calculated seasonal marginal energy prices (MPE) and marginal 

demand prices (MPD) for each building in the sample. The summer season is defined as the 

months May through September, and the winter season all other months. 

 DOE’s tariff data were last updated in 2004. To convert to 2010 dollars, two datasets 

were used: The report Average Regulated Retail Price of Electricity22 for the years 2004 through 

2007, and the Edison Electric Institute (EEI) Typical Bills and Average Rate reports for 200723

through 2010.24,25 Based on these data, a weighted-average price escalation factor for each region 

was calculated using consumer counts as the weights. The consumer counts come from the most 

recent EIA Form 861 data.13 The EEI data cover only publicly-owned companies. An analysis of 

EIA data from 2003 through 2006 showed that the rate of price escalation for publicly versus 

privately owned utility companies does not differ significantly, so the same escalation factors are 

used for both market sectors. 

 

a See Chapter 7. Energy Use and End-Use Load Characterization for details regarding DOE’s treatment of the 

CBECS sample.
8-19

Table 8.3.6 Average Seasonal Marginal Energy and Demand Prices By Census 

Division (2010$) 

Census Division Marginal Energy Price ($/kWh) Marginal Demand Price ($/kW)

Summer Winter Summer Winter

1.0 0.11 0.10 16.46 12.98

2.0 0.09 0.09 14.90 13.15

3.0 0.06 0.05 14.04 12.70

4.0 0.05 0.05 7.10 5.65

5.0 0.07 0.07 10.12 9.83

6.0 0.06 0.06 9.24 8.87

7.0 0.09 0.07 7.18 5.89

8 North 0.05 0.05 3.97 3.94

8 South 0.07 0.08 9.90 9.49

9 North 0.06 0.06 3.48 3.48

9 South 0.11 0.11 9.97 4.54

8.3.6 Load Growth Trends

The LCC analysis looks at a cross-section of transformers. DOE applied a load growth 

trend to each new transformer as part of its sensitivity analysis. Spreadsheet users have the 

choice of three scenarios using the Transformer Load Growth/Year drop-box on the “Summary” 

worksheet. The three scenarios for load growth are: no growth, one-half-percent-per-year 

growth, and one-percent-per-year growth. DOE used as the default scenario a no load growth for 

liquid-immersed transformers3

8.3.7 Electricity Cost and Price Trends

and dry-type transformers. 

For the relative change in electricity cost and prices for future years, DOE used the price 

trends from three AEO2010 forecast scenarios from EIA.26 LCC spreadsheet users have the 

choice of these three scenarios:

1. AEO2010 Low Growth scenario 

2. AEO2010 Reference scenario

3. AEO2010 High Growth scenario

Figure 8.3.3 shows the trends for the three AEO2010 price projections. Because 

AEO2010 does not forecast beyond 2035, DOE extrapolated the values in later years after 2035

from their relative sources. To arrive at values for these later years, DOE used the price trend of 

the forecast from 2015 to 2035 to establish prices in the years after 2036. This method of 

extrapolation is in line with methods currently used by the EIA to forecast fuel prices for the 

Federal Energy Management Program (FEMP). 

The default electricity price trend scenario that DOE used in the LCC analysis is the trend 

from the AEO2010 Reference case. Spreadsheets used in calculating the LCC have the 
8-20

capability to analyze the other electricity price trend scenarios, namely the AEO2010 High and 

Low Growth price trends. 

Figure 8.3.3 AEO 2010 Electricity Price Forecasts

8.3.8 Discount Rate

The discount rate is the rate at which future expenditures are discounted to estimate their 

present value. DOE derived the discount rates selected for the transformer LCC analysis from 

estimates of the cost of capital for companies that purchase transformers. Following financial 

theory, the cost of capital can be interpreted in three ways: 1) It is the discount rate that should be 

used to reduce the future value of cash flows to be derived from a typical company project or 

investment; 2) it is the economic cost to the firm of attracting and retaining capital in a 

competitive environment; and 3) it is the return that investors require from their investment in a 

firm’s debt or equity.27 DOE primarily used the first interpretation. Most companies use both 

debt and equity capital to fund investments; for most companies, therefore, the cost of capital is 

the weighted average of the cost to the firm of equity and debt financing.28

DOE estimated the cost of equity financing using the Capital Asset Pricing Model 

(CAPM). The CAPM, among the most widely used models to estimate the cost of equity 

financing, assumes that the cost of equity is proportional to the amount of systematic risk 

associated with a firm. For example, the cost of equity financing tends to be high when a firm 

faces a large degree of systematic risk, and the cost tends to be low when the firm faces a small 

degree of systematic risk.

 The degree of systematic risk facing a firm and the subsequent cost of equity financing 

are determined by several variables, including the risk coefficient of a firm (beta, or B), the 

expected return on risk-free assets (Rf), and the additional return expected on assets facing 

80%

85%

90%

95%

100%

105%

110%

115%

120%

2005 2010 2015 2020 2025 2030 2035

Real Price Relative to 2007

Year

Reference Case High Growth Low Growth
8-21

average market risk (which is known as the equity risk premium, or ERP). The beta indicates the 

degree of risk associated with a given firm, relative to the level of risk (or price variability) in the 

overall stock market. Betas usually vary between 0.5 and 2.0. A firm with a beta of 0.5 faces half 

the risk of other stocks in the market; a firm with a beta of 2.0 faces twice the overall stock 

market risk.

 Following this approach, the cost of equity financing for a particular company is given by 

the equation: 

ke = Rf + (B × ERP)

where:

ke = the cost of equity for a company, 

Rf = the expected return of the risk-free asset,

B = the beta of the company stock, and 

ERP = the expected equity risk premium, or the amount by which investors expect 

the future return on equities to exceed that on the riskless asset. 

 The cost of debt financing (kd) is the yield or interest rate paid on money borrowed by a 

company (raised, for example, by selling bonds). As defined here, the cost of debt includes 

compensation for default risk and excludes deductions for taxes. 

DOE estimated the cost of debt for companies by adding a risk adjustment factor (Ra) to 

the current yield on long-term corporate bonds (the risk-free rate). This procedure is used to 

estimate current (and future) company costs to obtain debt financing. The adjustment factor is 

based on indicators of company risk, such as credit rating or variability of stock returns. 

 The discount rate of companies is the weighted average cost of debt and equity financing, 

less expected inflation. DOE estimated the discount rate using the equation:

k = (ke × we) + (kd × wd) 

where:

k = the (nominal) cost of capital,

ke and kd = the expected rates of return on equity and debt, respectively, and 

we and wd = the proportion of equity and debt financing, respectively. 

 The real discount rate deducts expected inflation from the nominal rate. The expected 

return on risk-free assets, or the risk-free rate, is defined by the current yield on long-term 

government bonds. The ERP represents the difference between the expected (average) stock 

market return and the risk-free rate.29 DOE adjusts the risk-free rate for inflation to arrive at the 

value of the real risk-free rate, which is then used to calculate the CAPM estimate of the real 

discount rate as described above.30

Table 8.3.6 shows the typical owners of transformers, grouped by transformer type 

owned (represented by the design lines DOE used in the engineering analysis). DOE used a 
8-22

sample of approximately 4,500companies drawn from these owner categories to represent 

transformer purchasers. DOE took the sample from the list of companies included on the 

Damodaran Online website.31 DOE obtained the firm beta, the percent of debt and equity 

financing, the risk-free rate, and the equity risk premium from Damodaran Online. 

Table 8.3.7 Typical Owners of Different Types of Transformers

Design Line Typical Ownership Categories

1, 2, 3, 4 Electric utilities, both publicly owned and investor-owned

5, 6, 7 Electric utilities, commercial property owners, commercial and industrial

8, 9, 10, 11, 12, 13 Companies, government offices

 Transformers are purchased and owned by electric utilities (publicly and investorowned), C&I companies, the owners of commercial buildings (property owners), and the 

government. Table 8.3.7 shows average values for industrial companies, commercial companies, 

commercial property owners, and investor owned utilities. The risk-free rate and equity risk 

premium are constant across sectors in each year, but the cost of debt, percent debt financing, 

and systematic firm risk vary by sector. For example, average systematic firm risk of all private 

firms in the industrial sector is close to 1.0, while systematic firm risk in the utility sector 

averages close to 0.8. Similarly, industrial companies have been consistently financed with 

approximately 75% equity and 25% debt, while investor owned utilities (IOUs) have averaged 

55% equity and 45% debt. 

DOE estimated the cost of debt financing for these companies from the long-term 

government bond rate and the standard deviation of the stock price. Publicly owned utilities, 

including municipals and cooperatives, do not issue stock and tend to be financed with debt. 

DOE obtained the cost of debt for these companies from information provided in FERC Form 1 

filings. Finally, for government-office-type owners, the discount rate represents an average of 

the Federal rate and the State and local bond rate. DOE drew the Federal rate directly from the 

U.S. Office of Management and Budget discount rate for investments in government building 

energy efficiency.32 DOE estimated the State and local discount rate from the interest rate on 

State and local bonds between 1985 and 2009.33

 As mentioned above, the cost of capital may be viewed as the discount rate that should be 

used to reduce the future value of typical company project cash flows. It is a nominal discount 

rate, since anticipated future inflation is included in both stock and bond expected returns. 

Deducting expected inflation from the cost of capital provides estimates of the real discount rate 

by ownership category (Table 8.3.8). The mean real discount rate for these companies varies 

between 3.1 percent (government offices) and 6.8 percent (industrial companies). 
8-23

Table 8.3.8 Variables Used to Estimate Company Discount Rates 

Sector Year β Rf ERP Ra we wd

Industrial Companies 

(SIC 1-4) 

2005 1.03 3.47% 3.89% 1.50% 79% 21%

2006 1.00 3.44% 4.55% 2.00% 81% 19%

2007 1.03 3.74% 3.80% 2.00% 78% 22%

2008 1.10 4.21% 2.19% 4.00% 73% 27%

2009 1.06 4.15% 3.20% 4.00% 76% 24%

Commercial 

Companies 

(SIC 5-8) 

2005 0.88 3.47% 3.89% 1.25% 80% 20%

2006 0.88 3.44% 4.55% 1.25% 78% 22%

2007 0.90 3.74% 3.80% 1.25% 75% 25%

2008 0.95 4.21% 2.19% 3.00% 64% 36%

2009 0.94 4.15% 3.20% 4.00% 68% 32%

Commercial Property 

Owners

(SIC 6720) 

2005 0.70 3.47% 3.89% 0.25% 77% 23%

2006 0.84 3.44% 4.55% 0.50% 55% 45%

2007 0.91 3.74% 3.80% 0.50% 60% 40%

2008 1.06 4.21% 2.19% 3.00% 47% 53%

2009 1.22 4.15% 3.20% 3.00% 56% 44%

Utilities, InvestorOwned

(SIC 49) 

2005 0.86 3.47% 3.89% 0.50% 61% 39%

2006 0.92 3.44% 4.55% 0.25% 61% 39%

2007 0.88 3.74% 3.80% 0.25% 60% 40%

2008 0.79 4.21% 2.19% 1.00% 50% 50%

2009 0.76 4.15% 3.20% 1.50% 51% 49%

*SIC Codes refer to the U.S. Standard Industrial Classification system.

Table 8.3.9 Real Discount Rates by Transformer Ownership Category

Ownership Category SIC 

Codes*

Mean Real

Discount Rate 

%

Standard

Deviation 

%

Number of

Observations

Industrial Companies 1 - 4 6.8 1.5 11,944

Commercial Companies 5 - 8 6.2 1.5 9815

Commercial Property Owners 6720 5.5 0.9 27

Utilities, Investor-Owned 49 5.2 0.8 314

Utilities, Publicly Owned n/a 3.9 0.4 7

Government Offices n/a 3.1 1.2 26

 Because IOUs purchase the bulk of many transformer design lines evaluated here, the 

discount rates calculated for that sector (see Table 8.3.8) are particularly important. DOE 
8-24

estimated that the average IOU real discount rate is 5.2 percent. The 5.2 percent figure is an 

after-tax discount rate, representing the return required by such utilities to attract financing. 

Private financial data companies, including Ibbotson Associates, offer similar estimates. Using 

Ibbotson Associates debt, equity, standard deviation of stock price, and company beta statistics 

for 2008 in the Electric, Gas, and Sanitary Services sector (SIC 49), DOE estimates a similar 

discount rate of 5.3 percent.34 DOE uses the value of 5.2 percent, estimated from the companylevel Damodaran data, because it is tailored specifically to IOUs, not the broader SIC 49 sector.

DOE’s approach for estimating the cost of capital provides a measure of the discount rate 

spread as well as the average discount rate. DOE inferred the discount rate spread by ownership 

category from the standard deviation, which ranges between 0.4 percent and 1.5 percent (Table 

8.3.9). Publicly owned utility and property owner discount rates are narrowly concentrated 

around their mean value. By contrast, C&I company discount rates are dispersed across a broader 

range.

 Different combinations of commercial property owners and commercial, industrial, and 

utility buyers purchase the different transformer design lines included in the engineering analysis 

(Chapter 5). Accordingly, DOE constructed the discount rates associated with any given design 

line from different combinations of commercial property owner, commercial, industrial, and 

utility discount rates. For example, transformer design line 9 is purchased by commercial 

property owners, C&I companies, and the government. Roughly 19 percent of customers are 

commercial property owners, 19 percent are industrial companies, 54 percent are commercial 

companies, and 7.9 percent are government offices (Table 8.3.9).35

DOE estimated discount rate distributions for the different design lines as a weighted

average of the distributions for the different ownership types. 

Table 8.3.10 Transformer Ownership by Design Line

Transformer

Design Line

Property

Owners

%

Industrial

Companies

%

Commercial 

Companies

%

InvestorOwned

Utilities

%

Publicly

Owned

Utilities

%

Government

Offices

%

1 0.4 0.5 0.9 72.0 26.0 0.2

2 0.4 0.5 0.9 72.0 26.0 0.2

3 2.1 2.4 4.5 80.0 10.0 1.0

4 0.4 0.5 0.9 72.0 26.0 0.2

5 9.5 9.5 27.0 35.0 15.0 4.0

9 19.0 19.0 54.0 0 0 7.9

10 19.0 19.0 54.0 0 0 7.9

11 19.0 19.0 54.0 0 0 7.9

12 19.0 19.0 54.0 0 0 7.9

13 19.0 19.0 54.0 0 0 7.9

Source: DOE contractors.
8-25

8.3.9 Effective Date of Standard

The effective date of the revised energy efficiency standard for distribution transformers 

is four years after DOE issues the final rule. DOE assumed that it will issue the final rule in 

2012, so the new standard will take effect in 2016. DOE calculated the LCC for all users as if 

each new distribution transformer purchase occurs in the year the standard takes effect. It based 

the cost of the equipment on that year; however, as stated above, DOE expresses all dollar values 

in 2010$. 

8.3.10 Transformer Service Life

DOE defined distribution transformer service life as the age at which the transformer 

retires from service. DOE assumed, based on ORNL-6847, Determination Analysis of Energy 

Conservation Standards for Distribution Transformers,

36

8.3.11 Maintenance Costs

that the average life of distribution 

transformers is 32 years. This lifetime assumption includes a constant failure rate of 0.5 

percent/year due to lightning and other random failures unrelated to transformer age, and an 

additional corrosive failure rate of 0.5 percent/year starting at year 15. DOE adjusted the 

retirement distribution to maintain an average life of 32 years.

The maintenance cost is the cost to the consumer of maintaining equipment operation. 

The maintenance cost is not the cost associated with the replacement or repair of components 

that have failed. Rather, it is associated with general maintenance. DOE assumed that the cost 

for general maintenance will not change with increased efficiency. In practice, there is little 

scheduled maintenance for transformers. Maintenance consists of brief annual checks for dust 

buildup, vermin infestation, and accident or lightning damage. 

8.3.12 Power Factor

The power factor is the real power divided by the apparent power. Real power is the time 

average of the instantaneous product of voltage and current. Apparent power is the product of 

the root mean square (RMS) voltage times the RMS current. Transformer efficiency 

specifications, such as NEMA's TP 1-2002, assume a power factor of 1.0.1

 Therefore, DOE used 

a power factor of 1.0, both in calculating the efficiency levels in the engineering analysis and 

when preparing candidate standard levels for the Preliminary Analysis. 

However, in real-world installations, the loads experienced by distribution transformers 

are likely to have power factors of less than 1.0. Because the LCC analysis models transformers 

that are installed and operating in the field, DOE created the LCC spreadsheet with an adjustable 

power factor, enabling the LCC to run at lower power factor values. In the absence of any 

specific data or guidance on the appropriate power factor, DOE used 1.0 for this LCC analysis. 
8-26

8.3.13 Default Scenario

 DOE developed distinct scenarios for several key input parameters. It describes these 

distinct scenarios as low, medium, and high. For each of the key inputs, DOE chose the medium 

designation as the default scenario. The overall default scenario used in the LCC analysis has 

the following values: 

• transformer load growth/year: medium (one percent) for liquid-immersed, low (zero 

percent) for dry-type, 

• transformer loading (relative to current estimate): medium (zero percent), 

• electricity prices (relative to current estimate): medium (zero percent), 

• transformer customer As and Bs: medium, 

• future energy price trend: AEO2010 reference. 

Other scenarios can readily be used to explore sensitivities to variations of these key 

variables.

8.4 LIFE-CYCLE COST RESULTS

This section presents LCC results for the efficiency improvement levels evaluated for all 

13 design lines. Table 8.4.1 provides an overview of the seven candidate standard levels DOE 

evaluated for each of the 13 design lines examined for the preliminary analysis. The lowest 

efficiency candidate standard level is baseline and the highest is the most efficient design 

identified in the engineering analysis. The remaining six efficiency levels are spread between 

these two bounds. DOE expresses all the candidate standard levels in terms of efficiency, with 

no explicit or implicit technology assumed. The column labeled “Base 1+” shows by how much 

the given standard level exceeds the baseline. DOE based the results presented in this section on 

the inputs described in section 8.3. 

One of the primary impacts of an energy efficiency standard is the change in the set of 

transformer designs available for purchase and their corresponding loss characteristics: load 

losses (LL) and no-load losses (NL). This impact is illustrated in the LL versus NL graph 

(worksheet labeled: LL versus NL in the LCC spreadsheet). 
8-27

Table 8.4.1 Candidate Standard Levels Evaluated For Each Design Line 

Design Line

1 2 3 4 5 6 7 8 9 10 11 12 13

Candidate Standard Level

Baseline % 99.08 98.91 99.42 99.08 99.42 98 98 98.6 98.82 99.22 98.67 99.12 99.15

1 

Base + % 0.09 0.11 0.06 0.09 0.06 0.23 0.23 0.2 0.15 0.09 0.17 0.09 0.1

Efficiency % 99.17 99.02 99.48 99.17 99.48 98.23 98.23 98.8 98.97 99.31 98.84 99.21 99.25

2 

Base + % 0.19 0.22 0.12 0.19 0.12 0.47 0.47 0.42 0.3 0.18 0.33 0.18 0.2

Efficiency % 99.27 99.13 99.54 99.27 99.54 98.47 98.47 99.02* 99.12 99.4 99 99.3 99.35

3 

Base + % 0.28 0.33 0.15 0.28 0.15 0.6 0.6 0.59 0.46 0.28 0.5 0.27 0.31

Efficiency % 99.36 99.24 99.57 99.36 99.57 98.6* 98.6* 99.19 99.28 99.5 99.17 99.39 99.46

4 

Base + % 0.38 0.44 0.19 0.38 0.19 0.7 0.7 0.81 0.61 0.37 0.66 0.36 0.41

Efficiency % 99.46 99.35 99.61 99.46 99.61 98.7 98.7 99.41 99.43 99.59 99.33 99.48 99.56

5 

Base + % 0.47 0.55 0.25 0.47 0.25 0.93 0.93 0.99 0.76 0.46 0.83 0.45 0.51

Efficiency % 99.55 99.46 99.67 99.55 99.67 98.93 98.93 99.59 99.58 99.68 99.5 99.57 99.66

6 

Base + % 0.52 0.31 0.52 0.31 1.17 1.17 0.54

Efficiency % 99.6 99.73 99.6 99.73 99.17 99.17 99.66

7 

Base + % 0.34 1.4 1.4

Efficiency % 99.76 99.4 99.4

*NEMA Premium

Figure 8.4.2 provides an illustration of the LL versus NL graph taken from the LCC 

spreadsheet for design line 1, using the CSL 1. Since each design line has a unique set of 

engineering constraints, the LL-versus-NL graph for each design will be different. This graph 

plots an example of a Crystal Ball LCC run. It shows different sets of designs by their load 

losses at rated load, and their no-load losses. Potential designs are shown as both small dots and 

small triangles. The selected designs not subject to standard constraints are plotted as circles. 

The designs subject to standards constraints are plotted as dots. As the standard level increases, 

the cluster of selected designs moves to the left (to the area of the graph with lower losses), and 

so does the set of constrained designs. The efficiency level rating is defined at 50 percent 

(liquid-immersed and medium-voltage, dry-type), while the load and no-load losses for the 

design assumptions are defined by nameplate loading (100 percent). For those designs with 

higher load losses, the heating from losses causes the actual efficiency to drop, shifting the 

design to the right. 
8-28

Figure 8.4.2 Design Load Losses (LL) versus No-Load Losses 

(NL) in the Basecase and CSL 1 for Design Line 1

The following 13 tables present the summary results from DOE’s LCC analysis. For 

each evaluated design line and each candidate standard level, DOE presents the percent 

efficiency, the percent of evaluated transformer purchases that would experience negative, zero, 

and positive LCC savings when subject to the candidate standard level, and the mean LCC 

savings. DOE presents these summary results for consideration; it has not selected any specific 

candidate standard level for any design line. Graphical representations such as the results 

presented in Figure 8.4.3 can be for each candidate standard level using the spreadsheet tool.

0.00

100.00

200.00

300.00

400.00

500.00

600.00

700.00

800.00

900.00

1,000.00

0 50 100 150 200 250

Load Losses (watts)

No Load Losses (watts)

Design Load Losses (LL) vs No-Load Losses (NL)

at rated load

Available Designs

Selected Designs, Base

Selected Designs, Standard
8-29

Figure 8.4.3 Distribution of LCC Savings Results for DL2, CSL 2 

8.4.2 Design Line 1 Results

Table 8.4.2 presents the summary of the LCC analysis for the representative unit from 

design line 1, a 50 kVA, liquid-immersed, single-phase, pad-mounted transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.17 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $2,149, while the 

installation cost was $1,381. 

Table 8.4.2 Summary Life-Cycle Cost Results for Design Line 1 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.17 99.27 99.36 99.46 99.55 99.60 NA

Transformers with Net LCC 

Cost (%) 31.81 0.61 1.93 4.02 22.00 50.21 NA

Transformers with No Change in 

LCC (%) 14.22 11.43 9.58 7.92 0.08 0.00 NA

Transformers with Net LCC 

Benefit (%) 53.97 87.96 88.49 88.06 77.92 49.79 NA

Mean LCC Savings ($) 221 1139 1272 1348 945 173 NA
8-30

8.4.3 Design Line 2 Results

Table 8.4.3 presents the summary of the LCC analysis for the representative unit from 

design line 2, a 25 kVA, liquid-immersed, single-phase, pole-mounted transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.02 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $1,411, while the 

installation cost was $1,102. 

Table 8.4.3 Summary Life-Cycle Cost Results for Design Line 2 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency () 99.02 99.13 99.24 99.35 99.46 99.46 NA

Transformers with Net LCC 

Cost (%) 37.95 4.98 9.39 23.50 63.31 63.31 NA

Transformers with No Change in 

LCC (%) 2.32 1.42 0.76 0.47 0.00 0.00 NA

Transformers with Net LCC 

Benefit (%) 59.73 93.60 89.85 76.03 36.69 36.69 NA

Mean LCC Savings ($) 84 508 490 363 -130 -130 NA

8.4.4 Design Line 3 Results

Table 8.4.4 presents the summary of the LCC analysis for the representative unit from 

design line 3, a 500 kVA, liquid-immersed, single-phase distribution transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.48 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $26,987 , while the 

installation cost was $5,055. 

Table 8.4.4 Summary Life-Cycle Cost Results for Design Line 3 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency () 99.48 99.54 99.57 99.61 99.67 99.73 99.76 

Transformers with Net LCC 

Cost (%) 14.79 9.65 1.11 1.26 2.65 10.94 26.19 

Transformers with No Change in 

LCC (%) 42.55 5.24 5.21 4.08 2.71 0.46 0.00 

Transformers with Net LCC 

Benefit (%) 42.66 85.11 93.68 94.66 94.64 88.60 73.81 

Mean LCC Savings ($) 936 5705 7180 7662 8067 6560 4087 
8-31

8.4.5 Design Line 4 Results

Table 8.4.5 presents the summary of the LCC analysis for the representative unit from 

design line 4, a 150 kVA, liquid-immersed, three-phase distribution transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.17 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $6,139, while the 

installation cost was $2,228. 

Table 8.4.5 Summary Life-Cycle Cost Results for Design Line 4 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.17 99.27 99.36 99.46 99.55 99.60 NA

Transformers with Net LCC 

Cost (%) 1.96 0.78 4.81 7.32 24.48 39.80 NA

Transformers with No Change in 

LCC (%) 38.42 35.27 20.64 17.21 2.82 0.00 NA

Transformers with Net LCC 

Benefit (%) 59.62 63.95 74.55 75.47 72.70 60.20 NA

Mean LCC Savings ($) 2310 2592 2974 3203 2777 1309 NA

8.4.6 Design Line 5 Results

Table 8.4.6 presents the summary of the LCC analysis for the representative unit from 

design line 5, a 1500 kVA, liquid-immersed, three-phase distribution transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.48 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $26,987, while the 

installation cost was $5,055. 

Table 8.4.6 Summary Life-Cycle Cost Results for Design Line 5 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency () 99.48 99.54 99.57 99.61 99.67 99.73 NA

Transformers with Net LCC 

Cost (%) 18.66 0.67 1.58 2.91 14.62 74.36 NA

Transformers with No Change in 

LCC (%) 20.89 16.08 14.14 11.68 0.34 0.00 NA

Transformers with Net LCC 

Benefit (%) 60.45 83.25 84.28 85.41 85.04 25.64 NA

Mean LCC Savings ($) 7828 19260 19625 20092 18798 -10105 NA
8-32

8.4.7 Design Line 6 Results

Table 8.4.7 presents the summary of the LCC analysis for the representative unit from 

design line 6, a 25 kVA, low-voltage, dry-type, three-phase transformer with a 10 kilovolt (kV) 

basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 98.23. The consumer equipment cost before 

installation, which includes the manufacturer selling price, shipping costs, distributor markup, 

and retail markup, was $1,085, while the installation cost was $749. 

Table 8.4.7 Summary Life-Cycle Cost Results for Design Line 6 Representative Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency () 98.23 98.47 98.60 98.70 98.93 99.17 99.40

Transformers with Net LCC Cost 

(%) 21.54 41.22 48.35 30.86 35.34 53.03 90.53

Transformers with No Change in 

LCC (%) 0.68 0.00 0.00 0.00 0.00 0.00 0.00

Transformers with Net LCC Benefit 

(%) 77.78 58.78 51.65 69.14 64.66 46.97 9.47

Mean LCC Savings ($) 86 101 57 136 157 29 -820

8.4.8 Design Line 7 Results

Table 8.4.8 presents the summary of the LCC analysis for the representative unit from 

design line 7, a 75 kVA, low-voltage, dry-type, three-phase transformer with a 10 kilovolt (kV) 

basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 98.23 percent. The consumer equipment cost 

before installation, which includes the manufacturer selling price, shipping costs, distributor 

markup, and retail markup, was $2,432, while the installation cost was $1,157. 

Table 8.4.8 Summary Life-Cycle Cost Results for Design Line 7 Representative Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Efficiency () 98.23 98.47 98.60 98.70 98.93 99.17 99.40

Transformers with Net LCC Cost 

(%) 0.13 10.18 13.43 15.57 17.66 19.85 73.52

Transformers with No Change in 

LCC (%) 63.63 0.00 0.00 0.00 0.00 0.00 0.00

Transformers with Net LCC Benefit 

(%) 36.24 89.82 86.57 84.43 82.34 80.15 26.48

Mean LCC Savings ($) 243 533 626 658 817 914 -783

8.4.9 Design Line 8 Results

Table 8.4.9 presents the summary of the LCC analysis for the representative unit from 

design line 8, a 300 kVA, low-voltage, dry-type, three-phase transformer with a 20 kilovolt (kV) 
8-33

basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 99.80 percent. The consumer equipment cost 

before installation, which includes the manufacturer selling price, shipping costs, distributor 

markup, and retail markup, was $5,825, while the installation cost was $1,856. 

Table 8.4.9 Summary Life-Cycle Cost Results for Design Line 8 Representative Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.80 99.02 99.19 99.41 99.59 NA NA

Transformers with Net LCC Cost 

(%) 5.10 4.33 15.80 10.16 53.08 NA NA

Transformers with No Change in 

LCC (%) 0.00 0.00 0.00 0.00 0.00 NA NA

Transformers with Net LCC Benefit 

(%) 94.90 95.67 84.20 89.84 46.92 NA NA

Mean LCC Savings ($) 1376 2626 2396 3761 227 NA NA

8.4.10 Design Line 9 Results

Table 8.4.10 presents the summary of the LCC analysis for the representative unit from 

design line 9, a 300 kVA, medium-voltage, dry-type, three-phase transformer with a 45 kilovolt 

(kV) basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 98.97. The consumer equipment cost before 

installation, which includes the manufacturer selling price, shipping costs, distributor markup, 

and retail markup, was $10,344, while the installation cost was $2,225. 

Table 8.4.10 Summary Life-Cycle Cost Results for Design Line 9 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.97 99.12 99.28 99.43 99.58 NA NA

Transformers with Net LCC Cost 

(%) 23.00 24.31 20.05 26.88 66.22 NA NA

Transformers with No Change in 

LCC (%) 0.00 0.00 0.00 0.00 0.00 NA NA

Transformers with Net LCC Benefit 

(%) 77.00 75.69 79.95 73.12 33.78 NA NA

Mean LCC Savings ($) 1383 1455 2313 2557 -1572 NA NA

8.4.11 Design Line 10 Results

Table 8.4.11 presents the summary of the LCC analysis for the representative unit from 

design line 10, a 1500 kVA, medium-voltage, dry-type, three-phase transformer with a 45kV 

BIL. For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 99.31 percent. The consumer equipment cost before installation, which includes the 
8-34

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $39,893, 

while the installation cost was $4,473. 

Table 8.4.11 Summary Life-Cycle Cost Results for Design Line 10 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.31 99.40 99.50 99.59 99.68 NA NA

Transformers with Net LCC Cost 

(%) 48.05 21.86 10.43 11.90 71.94 NA NA

Transformers with No Change in 

LCC (%) 0.00 0.00 0.00 0.00 0.00 NA NA

Transformers with Net LCC Benefit 

(%) 51.95 78.14 89.57 88.10 28.06 NA NA

Mean LCC Savings ($) 2417 7604 12276 12988 -7204 NA NA

8.4.12 Design Line 11 Results

Table 8.4.12 presents the summary of the LCC analysis for the representative unit from 

design line 11, a 300 kVA, medium-voltage, dry-type, three-phase transformer with a 95kV BIL. 

For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 98.84 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $18,227, 

while the installation cost was $2,555. 

Table 8.4.12 Summary Life-Cycle Cost Results for Design Line 11 Representative Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.84 99.00 99.17 99.33 99.50 NA NA

Transformers with Net LCC Cost 

(%) 35.22 21.94 33.44 51.09 94.38 NA NA

Transformers with No Change in 

LCC (%) 0.00 0.00 0.00 0.00 0.00 NA NA

Transformers with Net LCC Benefit 

(%) 64.78 78.06 66.56 48.91 5.62 NA NA

Mean LCC Savings ($) 563 1943 1318 197 -7054 NA NA

8.4.13 Design Line 12 Results

Table 8.4.13 presents the summary of the LCC analysis for the representative unit from 

design line 12, a 1500 kVA, medium-voltage, dry-type, three-phase transformer with a 95kV 

BIL. For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 99.21 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $46,079, 

while the installation cost was $4,427. 
8-35

Table 8.4.13 Summary Life-Cycle Cost Results for Design Line 12 Representative Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.21 99.30 99.39 99.48 99.57 99.66 NA

Transformers with Net LCC Cost 

(%) 58.40 33.67 24.41 19.85 37.29 88.00 NA

Transformers with No Change in 

LCC (%) 0.00 0.00 0.00 0.00 0.00 0.00 NA

Transformers with Net LCC Benefit 

(%) 41.60 66.33 75.59 80.15 62.71 12.00 NA

Mean LCC Savings ($) -168 2644 7474 9063 4962 -18,429 NA

8.4.14 Design Line 13 Results

Table 8.4.14 presents the summary of the LCC analysis for the representative unit from 

design line 13, a 2000 kVA, medium-voltage, dry-type, three-phase transformer with a 125kV 

BIL. For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 99.25 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $55,345, 

while the installation cost was $5,077. 

Table 8.4.14 Summary Life-Cycle Cost Results for Design Line 13 Representative Unit

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.25 99.35 99.46 99.56 99.66 NA NA

Transformers with Net LCC Cost 

(%) 25.94 35.56 24.35 23.89 72.07 NA NA

Transformers with No Change in 

LCC (%) 0.00 0.00 0.00 0.00 0.00 NA NA

Transformers with Net LCC Benefit 

(%) 74.06 64.44 75.65 76.11 27.93 NA NA

Mean LCC Savings ($) 3050 4076 10600 11919 -9581 NA NA

8.5 LIFE-CYCLE COST SENSITIVITY ANALYSIS

DOE recognizes that there is always some uncertainty associated with engineering and 

economic analyses. To minimize that uncertainty, DOE strives to use the best techniques and the 

best data at its disposal. To cover the widest possible set of scenarios in this analysis, DOE used 

distributions of values for key inputs. For some variables, DOE went one step further by 

including in the analysis tool, the LCC spreadsheet, the ability to repeat the very same LCC 

analysis using values different from the default set used to produce DOE’s results. 

Detailed descriptions of all of the LCC input variables are included in the discussion of 

inputs in section 8.3, with additional information in Chapters 6 and 7. This section focuses on 
8-36

five key variables and the impact on the LCC results of assigning them a range of different 

values. The five variables and the location of their descriptive materials are as follows:

1. percentage of transformers purchased using A & B evaluation (see section 8.3.1);

2. transformer loading (see Chapter 6); 

3. electricity price trends (see section 8.3.7);

4. load growth trends (see section 8.3.6); and

This sensitivity analysis examines how sensitive the LCC results are to changes in key 

DOE assumptions. For this Preliminary Analysis, DOE conducted the sensitivity analysis on 

design lines 1, 7 and 13. This analysis treats each variable independently, the default values 

remain in effect for all variables except the one being examined. Sensitivity results should 

always be compared to the default results. Each of the five variables has three values—low, 

medium, and high—that are described in more detail in the individual input variable sections. 

The variable that characterizes the percentage of transformers purchased using A and B 

evaluation uses the same set of low and high values for both liquid-immersed and dry-type 

transformers, but different medium values for the different types of transformers. The low value 

represents a scenario where no transformer purchases are evaluated, the non-evaluating scenario. 

The high value represents a scenario where all transformer purchases are evaluated. The medium 

value for liquid-immersed transformers represents a scenario where 75 percent of the purchases 

are evaluated. The medium value for small-capacity, medium-voltage, dry-type transformers 

represents a scenario where 50 percent of purchases are evaluated. The medium value for largecapacity, medium-voltage, dry-type transformers represents a scenario where 80 percent of 

purchases are evaluated. 

For transformer loading, the medium scenario represents the output of the load simulation 

described in Chapter 7. The low scenario decreases the medium scenario load by 15 percent and 

the high scenario increases the medium scenario load by 15 percent. For load growth, the low, 

medium, and high annual scenarios are zero percent, one percent, and two percent, respectively. 

Electricity price trends use the AEO2010 low, reference, and high growth scenarios. . 

8.5.1 Design Line 1 Summary Sensitivity Results

The representative unit from design line 1 is a 50 kVA, liquid-immersed, single-phase, 

pad-mounted transformer. For this unit, the average efficiency of the baseline transformers 

selected during the LCC analysis was 99.17 percent. The consumer equipment cost before 

installation, which includes the manufacturer selling price, shipping costs, distributor markup, 

and retail markup, was $2,149, while the installation cost was $1,381. 

Table 8.5.1 and Figure 8.5.1 illustrate the LCC sensitivity to changes in the six userselectable variables. Each of the sensitivity runs for all the variables causes some change in the 

LCC results. For design line 1, it is the change in percentage of transformers loading that result

in the most significant changes in LCC savings for all candidate standard levels examined. DOE 

found that the variable labeled Loading stands significantly apart from the other variables for 

most candidate standard levels. The reason that transformer loading is so important is that it 
8-37

directly related to the amount of electricity that passes through a transformer. When the load on a 

transformer is increased, the load losses also increase; at higher loading levels the economic 

gains from the reduction in losses are realized when compared to the baseline. 

Table 8.5.1 Savings (2010$), Summary Table for Design Line 1 Representative Unit

Scenario

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.17% 99.27% 99.36% 99.46% 99.55% 99.60% NA

Baseline 193 1062 1177 1238 818 37 NA

Low A & B Distribution 24 1028 1204 1326 904 119 NA

High A & B Distribution 243 1072 1168 1210 790 11 NA

Low Loading 111 1101 1120 1066 498 -353 NA

High Loading 289 1017 1244 1438 1189 490 NA

Low Electricity Price 154 956 1045 1083 636 -159 NA

High Electricity Price 233 1168 1309 1393 999 232 NA

No Load Growth 166 1075 1158 1182 713 -92 NA

High Load Growth 224 1048 1199 1302 936 181 NA

Low Equipment Price 187 947 1327 1397 1009 265 NA

High Equipment Price 154 1114 1221 1266 773 -105 NA

Low Electricity Price Trend 163 977 1073 1117 677 -114 NA

High Electricity Price Trend 221 1139 1272 1348 945 173 NA

Figure 8.5.1 Average LCC Savings (2010$) by Scenario for 

Design Line 1

-600

-400

-200

0

200

400

600

800

1000

1200

1400

1600

99.17% 99.27% 99.36% 99.46% 99.55% 99.60% 99.60%

Average LCC Savings ($)

Transformer Efficiency (%)

Baseline

Low A & B Distribution Scenario

High A & B Distribution Scenario

Low Loading Scenario

High Loading Scenario

Low Electricity Price Scenario

High Electricity Price Scenario

No Load Grow th Scenario

High Load Grow th Scenario

Low Equipment Price Scenario

High Equipment Price Scenario

Low Electricity Price Trend Scenario

High Electricity Price Trend Scenario
8-38

8.5.2 Design Line 7 Summary Sensitivity Results

The representative unit from design line 7, a 75 kVA, low-voltage, dry-type, three-phase 

transformer with a 10 kilovolt (kV) basic impulse insulation level (BIL). For this unit, the 

average efficiency of the baseline transformers selected during the LCC analysis was 98.23 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $2,432, while the 

installation cost was $1,157. 

Table 8.5.2 and Figure 8.5.2 illustrate the LCC sensitivity to changes in the six userselectable variables for design line 7. Each of the sensitivity runs for all the variables causes 

some change in the LCC results. The changes in results tend to increase with the efficiency of 

the candidate standard level. For design line 7, the change in percentage of transformers 

purchased using A & B evaluation, low equipment prices, and, at higher efficiency levels, high 

electricity cost result in significantly larger changes in the LCC savings than do the other 

variables for all candidate standard levels examined. The purchase behavior described by A & B 

evaluation strongly affects how much energy is used when there is no standard, and thus affects 

the potential savings. The low savings from the high A & B distribution case result from the fact 

that DOE assumes that all purchasers place an economic value on losses and will purchase a 

transformer based on those values instead of lowest fist costs. For CSL 1 through 4, low 

equipment price shows the largest increase from the default assumptions, because of the limited 

material options used to produce high-efficiency transformers that become available at lower 

equipment prices. For candidate levels 5 and 6 high electricity prices result in higher LCC 

savings because of the higher economic value of avoided load and no-load losses due to the 

increased transformer efficiency.

Table 8.5.2 Savings (2010$), Summary Table for Design Line 7 Representative Unit

Scenario

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.23% 98.47% 98.60% 98.70% 98.93% 99.17% 99.40%

Baseline 243 533 626 658 817 914 -783

Low A & B Distribution 270 577 671 705 856 958 -739

High A & B Distribution 1 131 223 237 461 511 -1176

Low Loading 244 403 450 496 771 712 -1320

High Loading 244 598 715 739 839 1015 -515

Low Electricity Price 215 468 522 508 554 619 -1099

High Electricity Price 272 598 730 808 1080 1208 -467

Medium Load Growth 243 588 702 727 837 1000 -552

High Load Growth 243 652 787 806 859 1098 -291

Low Equipment Price 328 647 867 1050 1003 785 -843

High Equipment Price 320 607 726 815 561 499 -1540

Low Electricity Price Trend 224 472 532 534 628 684 -1067

High Electricity Price Trend 260 584 705 763 977 1108 -542
8-39

Figure 8.5.2 Average LCC Savings (2010$) by Scenario for 

Design Line 7

8.5.3 Design Line 13 Summary Sensitivity Results

The representative unit from design line 13 is a 2000 kVA, medium-voltage, dry-type, 

three-phase transformer with a 125kV BIL. For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 99.25 percent. The consumer equipment cost 

before installation, which includes the manufacturer selling price, shipping costs, distributor 

markup, and retail markup, was $55,345, while the installation cost was $5,077. 

Table 8.5.3 and Figure 8.5.3 illustrate the LCC sensitivity to changes in the six userselectable variables for design line 13. Each of the sensitivity runs for all the variables causes 

some change in the LCC results. The changes in results tend to increase with the efficiency of 

the candidate standard level. For design line 13, it is the change in percentage of transformers 

loading that result in the most significant increase in LCC savings for all candidate standard 

levels examined. DOE found that the variable labeled Loading stands significantly apart from 

the other variables for most candidate standard levels. The reason that transformer loading is so 

important is that it directly related to the amount of electricity that passes through a transformer. 

When the load on a transformer is increased, the load losses also increase; at higher loading 

levels the economic gains from the reduction in losses are realized when compared to the 

baseline.

-2000

-1500

-1000

-500

0

500

1000

1500

98.23% 98.47% 98.60% 98.70% 98.93% 99.17% 99.40%

Average LCC Savings ($)

Transformer Efficiency (%)

Baseline

Low A & B Distribution Scenario

High A & B Distribution Scenario

Low Loading Scenario

High Loading Scenario

Low Electricity Price Scenario

High Electricity Price Scenario

Medium Load Grow th Scenario

High Load Grow th Scenario

Low Equipment Price Scenario

High Equipment Price Scenario

Low Electricity Price Trend Scenario

High Electricity Price Trend Scenario
8-40

Figure 8.5.3 Average LCC Savings (2010$) by Scenario for 

Design Line 13

Table 8.5.3 LCC Savings (2010$), Summary Table for Design Line 13 

Scenario

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.25% 99.35% 99.46% 99.56% 99.66% NA NA

Baseline 3050 4076 10600 11919 -9581 NA NA

Low A & B Distribution 3556 5267 10598 12301 -9137 NA NA

High A & B Distribution 2924 3778 10601 11824 -9692 NA NA

Low Loading 2670 6992 13986 11583 -13353 NA NA

High Loading 3207 2733 9113 12071 -7919 NA NA

Low Electricity Price 1831 1137 6009 6548 -15556 NA NA

High Electricity Price 4270 7015 15191 17290 -3606 NA NA

Medium Load Growth 3218 2723 9059 12077 -7861 NA NA

High Load Growth 3406 1196 7315 12255 -5915 NA NA

Low Equipment Price 4310 5367 5489 7458 -12321 NA NA

High Equipment Price 2940 401 4455 4909 -20166 NA NA

Low Electricity Price Trend 2158 2272 7699 8131 -14105 NA NA

High Electricity Price Trend 3803 5597 13044 15117 -5756 NA NA

8.6 PAYBACK PERIOD

The PBP analysis is a common technique used to evaluate investment decisions. A more 

energy-efficient device will usually cost more to purchase than a device of standard energy 

-25000

-20000

-15000

-10000

-5000

0

5000

10000

15000

20000

99.25% 99.35% 99.46% 99.56% 99.66%

Average LCC Savings ($)

Transformer Efficiency (%)

Baseline

Low A & B Distribution Scenario

High A & B Distribution Scenario

Low Loading Scenario

High Loading Scenario

Low Electricity Price Scenario

High Electricity Price Scenario

Medium Load Grow th Scenario

High Load Grow th Scenario

Low Equipment Price Scenario

High Equipment Price Scenario

Low Electricity Price Trend Scenario

High Electricity Price Trend Scenario
8-41

efficiency. However, the more efficient device will usually cost less to operate, due to the 

reduction in energy use. The payback period is the time (usually expressed in years) it takes to 

recover the additional first cost of the efficient device, through its energy cost savings. Because 

the LCC analysis uses distributions of inputs, DOE gives results such as payback periods in the 

form of distributions. 

8.6.1 Payback Period

The PBP is the ratio of the increase in purchase expense (the purchase from a less 

efficient design to a more efficient design) to the decrease in annual operating expenditures. 

This type of calculation is known as a simple payback period because it does not take into 

account changes in operating expense over time.

PBP is found using the equation: 

PBP = ∆FC

∆OC �

where:

ΔFC = installed purchase price (first cost) of a transformer satisfying the candidate 

standard level minus the installed purchase price (first cost) of a transformer 

in the absence of the standard (assumes the transformer meeting the standard 

is more expensive than the transformer not subject to the standard) (2010$), 

and

ΔOC = operating cost of the transformer not subject to the standard minus the 

operating cost of the transformer subject to the standard (assumes the 

transformer meeting the candidate standard level has lower energy 

consumption, and hence lower operating cost, than the transformer not 

subject to the standard). Because ΔOC is expressed in annual terms, PBP is 

expressed in years. 

DOE calculates the PBP both for a distribution of transformers and for an average 

transformer. The PBP for the national average transformer uses the average values of the firstcost increase and operating-cost savings to calculate the PBP.

8.6.2 Inputs

The inputs to PBP are: 1) the purchase expense, otherwise known as the total installed 

consumer cost, or first cost, for each selected design; and 2) the annual (first year) operating 

expenditures for each selected design. The inputs to the purchase expense are the equipment 

price and the installation cost with appropriate markups. The inputs to the operating costs are the 

annual (first year) energy consumption and the electricity price. The distributional PBP uses the 

same inputs as the LCC analysis described in section 8.3, except that, since this is a simple 

payback, the electricity price DOE used is only for the year the standard takes effect, assumed 

here to be 2016. 
8-42

8.6.3 Baseline Scenario Complications

Since distribution transformers are not currently subject to energy efficiency standards, 

DOE developed the baseline scenario to estimate transformer purchase behavior in the current 

market. DOE’s default assumption for the baseline scenario was that some portion of 

transformer purchase decisions are based on TOC-type evaluations. Specifically, the default 

assumptions for the use of TOC-type evaluation are 75 percent for liquid-immersed transformers 

and 50 percent for medium-voltage, dry-type transformers, all using distributions of A and B 

evaluation factors. Especially at the lower candidate standard levels that DOE evaluated, the 

transformer purchases based on TOC may not satisfy the basic PBP assumptions of higher 

purchase price and lower operating costs for the transformers subject to the candidate standard. 

When these basic assumptions are not satisfied, the traditional PBP calculation loses its validity.

For example, a current (not subject to standards) transformer purchase decision based on 

TOC may have identical first cost (ΔFC = 0) to a transformer just meeting candidate standard 

level 1. In addition, the transformer meeting the standard may have a different operating cost 

from the transformer purchased without the standard. In such a situation, PBP = 0. In another 

example, a current transformer purchase decision based on TOC may result in a transformer 

costing more to purchase and install and consuming less electricity than a transformer that just 

meets baseline. In this case, the PBP calculation for the standards case is nonsensical, since it 

would imply a negative payback period. 

DOE’s method of calculating PBP is shown below. 

ΔFC = FC(Standard) - FC(Baseline)

(ΔFC is normally positive)

ΔOC = OC(Standard) - OC(Baseline)

(ΔOC is normally negative) 

PBP = - ΔFC / ΔOC

(For the normally positive ΔFC and the normally negative ΔOC, PBP is 

positive) 

Because ΔFC can also be zero or negative, and because ΔOC can also be zero or 

negative, there are nine possible cases that can be grouped into five computational cases. Table 

8.6.1 shows the possible relationships between ΔFC and ΔOC and the resultant effect on PBP.
8-43

Table 8.6.1 Possible ΔFC and ΔOC Combinations, for Payback Period Analysis 

Case # Possible Cases Effect on PBP Calculation

1 ΔFC > 0 and ΔOC < 0 Well-defined PBP

2 ΔFC = 0 and ΔOC = 0 Unaffected by the standard

3 ΔFC < 0 and ΔOC = 0

ΔFC > 0 and ΔOC = 0 Division by zero: PBP is undefined 

4 ΔFC = 0 and ΔOC > 0

ΔFC = 0 and ΔOC < 0 PBP = 0 

5 

ΔFC < 0 and ΔOC < 0, or

ΔFC > 0 and ΔOC > 0, or 

ΔFC < 0 and ΔOC > 0

Not valid: negative or double negative PBP 

8.6.4 Payback Period Results 

Tables 8.6.2 through 8.6.11 illustrate, for each of the 13 design lines and their 7 candidate 

standard levels, the mean PBP and the percentage of the 10,000 Monte Carlo simulations where 

the PBP calculation applies. For each candidate standard level for each design line, the sum of 

the categories “Transformers Unaffected by the Standard,” “Transformers having Well-Defined 

Payback Period,” and “Transformers having Undefined Payback Period” should equal 100 

percent.a

Figure 8.6.1

As the efficiency of the candidate standard levels increases, the percentage of purchase 

decisions where the PBPs are well-defined increases. illustrates the full PBP results 

from the simulation as a histogram that can be generated for all DLs and each CLS using the 

LCC spreadsheet tool. 

DOE calculates the PBP both for a distribution of transformers and for an average 

transformer. The PBP for the national average transformer uses the average values of the first 

cost increase and operating cost savings to calculate the PBP for the average transformer.

 

a

For simplicity of presentation, Cases 3, 4 and 5 in Table 8.6.1 have been grouped together into the “Transformers 

having Undefined Payback Period” category in Tables 8.6.2 through 8.6.15.
8-44

Figure 8.6.1 Distribution of Payback Period Results for DL 2, 

CSL 2

8.6.5 Design Line 1 Results

Table 8.4.2 presents the summary of the LCC analysis for the representative unit from 

design line 1, a 50 kVA, liquid-immersed, single-phase, pad-mounted transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.17 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $2,149, while the 

installation cost was $1,381. 
8-45

Table 8.6.2 Summary of Payback Period Results for Design Line 1 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 26.8 8.4 10.4 12.5 22.6 31.2 31.2

Transformers Unaffected by the 

TSL (%) 14.23 11.44 9.59 7.93 0.09 0.00 0.00

Transformers having Well 

Defined Payback (%) 78.62 88.56 90.40 91.91 98.45 98.80 98.80

Transformers having Undefined 

Payback (%) 7.15 0.00 0.01 0.16 1.46 1.20 1.20 

Mean Incremental First Cost ($) 1,381 1,371 1,405 1,449 1,562 1,692 1,692 

Mean Operating Cost Savings 

($) 194 147 134 123 112 105 105

Payback of Average 

Transformer 7.1 9.3 10.5 11.8 14.0 16.0 16.0

8.6.6 Design Line 2 Results

Table 8.4.3 presents the summary of the LCC analysis for the representative unit from 

design line 2, a 25 kVA, liquid-immersed, single-phase, pole-mounted transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.02 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $1,411, while the 

installation cost was $1,102. 

Table 8.6.3 Summary of Payback Period Results for Design Line 2 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 26.5 13.7 16.7 20.6 30.4 30.4 30.4

Transformers Unaffected by the 

TSL (%) 2.33% 1.43% 0.77% 0.48% 0.01% 0.01% 0.01%

Transformers having Well 

Defined Payback (%) 94.66% 98.41% 99.08% 99.36% 99.84% 99.84% 99.84%

Transformers having Undefined 

Payback (%) 3.01% 0.16% 0.15% 0.16% 0.16% 0.16% 0.16% 

Mean Incremental First Cost ($) 1,102 1,194 1,258 1,325 1,445 1,445 1,445

Mean Operating Cost Savings 

($) 124 93 84 78 73 73 73

Payback of Average 

Transformer 8.9 12.8 15.1 17.0 19.8 19.8 19.8
8-46

8.6.7 Design Line 3 Results

Table 8.4.4 presents the summary of the LCC analysis for the representative unit from 

design line 3, a 500 kVA, liquid-immersed, single-phase distribution transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.48 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $26,987 , while the 

installation cost was $5,055. 

Table 8.6.4 Summary of Payback Period Results for Design Line 3 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 18.3 12.2 8.1 9.1 11.1 17.3 22.7

Transformers Unaffected by the 

TSL (%) 42.56 5.25 5.22 4.09 2.72% 0.47% 0.00%

Transformers having Well 

Defined Payback (%) 51.23 94.39 94.63 95.84 97.14% 99.18% 99.72%

Transformers having Undefined 

Payback (%) 6.21 0.36 0.15 0.07 0.14% 0.35% 0.28%

Mean Incremental First Cost ($) 2,745 2,975 3,001 3,072 3,206 3,558 3,818 

Mean Operating Cost Savings 

($) 1,161 851 779 731 668 589 561

Payback of Average 

Transformer 2.4 3.5 3.9 4.2 4.8 6.0 6.8

8.6.8 Design Line 4 Results

Table 8.4.5 presents the summary of the LCC analysis for the representative unit from 

design line 4, a 150 kVA, liquid-immersed, three-phase distribution transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.17 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $6,139, while the 

installation cost was $2,228. 
8-47

Table 8.6.5 Summary of Payback Period Results for Design Line 4 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 18.3 12.2 8.1 9.1 11.1 17.3 22.7

Transformers Unaffected by the 

TSL (%) 42.56% 5.25% 5.22% 4.09% 2.72% 0.47% 0.00%

Transformers having Well 

Defined Payback (%) 51.23% 94.39% 94.63% 95.84% 97.14% 99.18% 99.72%

Transformers having Undefined 

Payback (%) 6.21% 0.36% 0.15% 0.07% 0.14% 0.35% 0.28% 

Mean Incremental First Cost ($) 2,745 2,975 3,001 3,072 3,206 3,558 3,818 

Mean Operating Cost Savings 

($) 1,161 851 779 731 668 589 561

Payback of Average 

Transformer 2.4 3.5 3.9 4.2 4.8 6.0 6.8

8.6.9 Design Line 5 Results

Table 8.4.6 presents the summary of the LCC analysis for the representative unit from 

design line 5, a 1500 kVA, liquid-immersed, three-phase distribution transformer. For this unit, 

the average efficiency of the baseline transformers selected during the LCC analysis was 99.48 

percent. The consumer equipment cost before installation, which includes the manufacturer 

selling price, shipping costs, distributor markup, and retail markup, was $26,987, while the 

installation cost was $5,055. 

Table 8.6.6 Summary of Payback Period Results for Design Line 5 Representative 

Unit

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 5.8 4.8 9.4 11.8 23.7 33.5 33.5

Transformers Unaffected by the 

CSL (%) 38.43% 35.28% 20.65% 17.22% 2.83% 0.00% 0.00%

Transformers having Well 

Defined Payback (%) 61.17% 64.55% 79.32% 82.68% 96.41% 98.20% 98.20% 

Transformers having Undefined 

Payback (%) 0.40% 0.17% 0.03% 0.10% 0.76% 1.80% 1.80%

Mean Incremental First Cost ($) 2,228 2,233 2,288 2,343 2,546 2,757 2,757

Mean Operating Cost Savings 

($) 430 416 386 364 318 298 298

Payback of Average 

Transformer 5.2 5.4 5.9 6.4 8.0 9.2 9.2
8-48

8.6.10 Design Line 6 Results

Table 8.4.7 presents the summary of the LCC analysis for the representative unit from 

design line 6, a 25 kVA, low-voltage, dry-type, three-phase transformer with a 10 kilovolt (kV) 

basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 98.23. The consumer equipment cost before 

installation, which includes the manufacturer selling price, shipping costs, distributor markup, 

and retail markup, was $1,085, while the installation cost was $749. 

Table 8.6.7 Summary of Payback Period Results for Design Line 6 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 12.5 19.2 19.7 15.0 15.6 18.8 33.0 

Transformers Unaffected by 

the CSL (%) 0.69% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Transformers having Well 

Defined Payback (%) 95.74% 99.46% 99.98% 100.00% 100.00% 100.00% 100.00%

Transformers having 

Undefined Payback (%) 3.57% 0.53% 0.02% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost 

($) 64 258 397 426 603 849 1,645 

Mean Operating Cost Savings 

($) 9 24 31 39 53 63 72

Payback of Average 

Transformer 6.8 10.8 12.6 11.0 11.4 13.4 22.8

8.6.11 Design Line 7 Results

Table 8.4.8 presents the summary of the LCC analysis for the representative unit from 

design line 7, a 75 kVA, low-voltage, dry-type, three-phase transformer with a 10 kilovolt (kV) 

basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 98.23 percent. The consumer equipment cost 

before installation, which includes the manufacturer selling price, shipping costs, distributor 

markup, and retail markup, was $2,432, while the installation cost was $1,157. 
8-49

Table 8.6.8 Summary of Payback Period Results for Design Line 7 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 0.3 7.8 9.8 11.2 12.3 12.7 24.0 

Transformers Unaffected by 

the CSL (%) 36.19% 99.76% 100.00% 100.00% 100.00% 100.00% 100.00%

Transformers having Well 

Defined Payback (%) 63.64% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Transformers having 

Undefined Payback (%) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 

Mean Incremental First Cost 

($) -4 164 406 654 1,143 1,450 3,296 

Mean Operating Cost 

Savings ($) 14 43 66 87 132 160 199

Payback of Average 

Transformer -0.3 3.8 6.2 7.6 8.7 9.0 16.5

8.6.12 Design Line 8 Results

Table 8.4.9 presents the summary of the LCC analysis for the representative unit from 

design line 8, a 300 kVA, low-voltage, dry-type, three-phase transformer with a 20 kilovolt (kV) 

basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 99.80 percent. The consumer equipment cost 

before installation, which includes the manufacturer selling price, shipping costs, distributor 

markup, and retail markup, was $5,825, while the installation cost was $1,856. 

Table 8.6.9 Summary of Payback Period Results for Design Line 8 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 6.9 6.9 11.9 10.7 18.6 NA NA

Transformers Unaffected by the 

CSL (%) 99.96% 100.00% 100.00% 100.00% 100.00% NA NA

Transformers having Well 

Defined Payback (%) 0.00% 0.00% 0.00% 0.00% 0.00% NA NA

Transformers having Undefined 

Payback (%) 0.00% 0.00% 0.00% 0.00% 0.00% NA NA

Mean Incremental First Cost ($) 490 1,169 3,067 3,896 7,935 NA NA

Mean Operating Cost Savings 

($) 116 238 371 510 610 NA NA

Payback of Average 

Transformer 4.2 4.9 8.3 7.6 13.0 NA NA
8-50

8.6.13 Design Line 9 Results

Table 8.4.10 presents the summary of the LCC analysis for the representative unit from 

design line 9, a 300 kVA, medium-voltage, dry-type, three-phase transformer with a 45 kilovolt 

(kV) basic impulse insulation level (BIL). For this unit, the average efficiency of the baseline 

transformers selected during the LCC analysis was 98.97. The consumer equipment cost before 

installation, which includes the manufacturer selling price, shipping costs, distributor markup, 

and retail markup, was $10,344, while the installation cost was $2,225. 

Table 8.6.10 Summary of Payback Period Results for Design Line 9 Representative 

Unit

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 13.6 13.6 13.0 14.1 21.7 NA NA

Transformers Unaffected by the 

CSL (%) 1.51% 0.00% 0.00% 0.00% 0.00% NA NA

Transformers having Well 

Defined Payback (%) 96.99% 100.00% 100.00% 100.00% 100.00% NA NA

Transformers having Undefined 

Payback (%) 1.50% 0.00% 0.00% 0.00% 0.00% NA NA

Mean Incremental First Cost ($) 1,072 2,666 4,150 5,833 10,709 NA NA

Mean Operating Cost Savings 

($) 159 287 446 586 716 NA NA

Payback of Average 

Transformer 6.7 9.3 9.3 9.9 14.9 NA NA

8.6.14 Design Line 10 Results

Table 8.4.11 presents the summary of the LCC analysis for the representative unit from 

design line 10, a 1500 kVA, medium-voltage, dry-type, three-phase transformer with a 45kV 

BIL. For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 99.31 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $39,893, 

while the installation cost was $4,473. 
8-51

Table 8.6.11 Summary of Payback Period Results for Design Line 10 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 18.5 13.3 10.4 11.1 22.5 NA NA

Transformers Unaffected by the 

CSL (%) 0.45% 0.55% 0.00% 0.00% 0.00% NA NA

Transformers having Well 

Defined Payback (%) 99.11% 98.91% 100.00% 100.00% 100.00% NA NA

Transformers having Undefined 

Payback (%) 0.44% 0.54% 0.00% 0.00% 0.00% NA NA

Mean Incremental First Cost ($) 6,200 7,990 11,418 14,429 34,282 NA NA

Mean Operating Cost Savings 

($) 609 1,049 1,577 1,846 2,193 NA NA

Payback of Average 

Transformer 10.2 7.6 7.2 7.8 15.6 NA NA

8.6.15 Design Line 11 Results

Table 8.4.12 presents the summary of the LCC analysis for the representative unit from 

design line 11, a 300 kVA, medium-voltage, dry-type, three-phase transformer with a 95kV BIL. 

For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 98.84 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $18,227, 

while the installation cost was $2,555. 

Table 8.6.12 Summary of Payback Period Results for Design Line 11 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 17.5 13.2 15.3 18.5 34.4 NA NA

Transformers Unaffected by the 

CSL (%) 4.34% 0.06% 0.00% 0.00% 0.00% NA NA

Transformers having Well 

Defined Payback (%) 91.33% 99.89% 100.00% 100.00% 100.00% NA NA

Transformers having Undefined 

Payback (%) 4.33% 0.05% 0.00% 0.00% 0.00% NA NA

Mean Incremental First Cost ($) 1,109 2,868 4,428 6,183 12,395 NA NA

Mean Operating Cost Savings 

($) 117 328 408 476 529 NA NA

Payback of Average 

Transformer 9.5 8.7 10.8 13.0 23.4 NA NA
8-52

8.6.16 Design Line 12 Results

Table 8.4.13 presents the summary of the LCC analysis for the representative unit from 

design line 12, a 1500 kVA, medium-voltage, dry-type, three-phase transformer with a 95kV 

BIL. For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 99.21 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $46,079, 

while the installation cost was $4,427. 

Table 8.6.13 Summary of Payback Period Results for Design Line 12 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 23.1 15.6 13.8 13.0 16.0 27.6 NA

Transformers Unaffected by 

the CSL (%) 1.32% 0.23% 0.02% 0.00% 0.00% 0.00% NA

Transformers having Well 

Defined Payback (%) 97.37% 99.55% 99.97% 100.00% 100.00% 100.00% NA

Transformers having 

Undefined Payback (%) 1.31% 0.22% 0.01% 0.00% 0.00% 0.00% NA

Mean Incremental First Cost 

($) 4,713 8,407 13,585 15,426 23,146 44,114 NA

Mean Operating Cost Savings 

($) 352 799 1,468 1,699 2,049 2,298 NA

Payback of Average 

Transformer 13.4 10.5 9.3 9.1 11.3 19.2 NA

8.6.17 Design Line 13 Results

Table 8.4.14 presents the summary of the LCC analysis for the representative unit from 

design line 13, a 2000 kVA, medium-voltage, dry-type, three-phase transformer with a 125kV 

BIL. For this unit, the average efficiency of the baseline transformers selected during the LCC 

analysis was 99.25 percent. The consumer equipment cost before installation, which includes the 

manufacturer selling price, shipping costs, distributor markup, and retail markup, was $55,345, 

while the installation cost was $5,077. 
8-53

Table 8.6.14 Summary of Payback Period Results for Design Line 13 Representative 

Unit

 

Candidate Standard Level

1 2 3 4 5 6 7 

Mean Payback (Years) 14.4 17.4 13.7 13.8 21.8 NA NA

Transformers Unaffected by the 

CSL (%) 0.45% 1.17% 0.01% 0.00% 0.00% NA NA

Transformers having Well 

Defined Payback (%) 99.11% 97.67% 99.99% 100.00% 100.00% NA NA

Transformers having Undefined 

Payback (%) 0.44% 1.16% 0.00% 0.00% 0.00% NA NA

Mean Incremental First Cost ($) 5,878 13,325 18,456 25,644 48,706 NA NA

Mean Operating Cost Savings 

($) 621 1,256 2,018 2,641 3,158 NA NA

Payback of Average 

Transformer 9.5 10.6 9.1 9.7 15.4 NA NA

8.7 REBUTTABLE PRESUMPTION

The rebuttable presumption is a simplified method of determining the economic 

justification of a proposed energy efficiency standard. In evaluating the rebuttable presumption, 

DOE estimates the additional cost of purchasing a more efficient, standard-compliant product, 

and compares this cost to the value of the energy savings during the first year of operation of the 

product as determined by the applicable test procedure. If the additional first cost is less than 

three times the value of the energy savings (when the rebuttable payback period is less than three 

years), then the rebuttable presumption that such a standard level is economically justified is 

satisfied.

The rebuttable payback period differs from payback periods presented in other parts of 

this chapter in two important ways:

• The rebuttable payback period uses test procedure loading levels to evaluate losses, rather 

than DOE’s estimate of in-service loading conditions. 

• Other payback periods may consider total operating costs, whereas the rebuttable 

presumption payback period considers only the value of energy savings. In the case of 

distribution transformers, however, DOE estimates that the change in operating costs is 

solely due to energy savings. 

There are three key inputs into the rebuttable payback calculation: (1) the average 

efficiency; (2) the average installed cost; and (3) the cost of electricity. Given the average 

efficiency of the transformer, DOE calculated the losses on the transformer assuming the loading 

conditions from the test procedure. Multiplying the losses times the cost of electricity provided 
8-54

the operating cost, and then dividing incremental operating costs into incremental installed cost 

provided the estimate of the rebuttable payback period. 

Tables 8.7.1 through 8.7.4 show the different inputs into the rebuttable presumption 

payback period calculation. Table 8.7.1 shows the average transformer efficiency as a function 

of design line and standard level for CSL 1 through CSL 7. This is the average efficiency as 

determined by the customer choice model of the LCC calculation. The customer choice model 

provides a range of transformer design efficiencies that depends on a distribution of customer 

choices with respect to the value that customers place on reducing transformer design losses. 

Table 8.7.2 show the average transformer installed cost as a function of both design line and 

standard level. The average marginal cost of electricity is a function of transformer type, for 

liquid-immersed transformers it is estimated at 0.67 $/kWh and for dry-type transformers at 

0.059 $/kWh. The difference between the marginal cost of electricity for liquid-immersed and 

dry-type transformers is because liquid-immersed transformers tend to be owned by utilities, 

which pay the wholesale (rather than retail) cost of electricity. Table 8.7.3 show the first-year 

operating cost, which is the annual losses calculated from the test procedure assumptions times 

the average marginal cost of electricity. 

Table 8.7.4 show the rebuttable payback period as a function of design line and standard 

level. The table records how the rebuttable presumption is not satisfied for any design line 

except for design line 7, and it is satisfied for candidate standard level 1 only. 

 Assuming the design line results are representative of the corresponding rated capacity 

ranges as specified in the engineering chapter (Chapter 5), the rebuttable condition is satisfied for 

equipment class 6 at candidate standard level 1.

Table 8.7.1 Average Transformer Efficiency

Design 

Line

Rated 

Capacity 

(kVA) 

Candidate Standard Level

Base 1 2 3 4 5 6 7 

1 50 99.08% 99.20% 99.46% 99.46% 99.46% 99.55% 99.60% NA

2 25 98.92% 99.04% 99.31% 99.31% 99.39% 99.48% NA NA

3 500 99.50% 99.50% 99.66% 99.66% 99.66% 99.73% 99.73% 99.75% 

4 150 99.48% 99.48% 99.48% 99.48% 99.48% 99.58% 99.60% NA

5 1500 99.46% 99.49% 99.66% 99.66% 99.66% 99.67% 99.73% NA

6 25 98.02% 98.27% 98.49% 98.61% 98.71% 98.97% 99.18% 99.40% 

7 75 98.29% 98.29% 98.49% 98.61% 98.70% 99.00% 99.18% 99.40% 

8 300 98.66% 98.85% 99.04% 99.23% 99.45% 99.59% NA NA

9 300 98.82% 99.01% 99.15% 99.33% 99.44% 99.58% NA NA

10 1500 99.23% 99.31% 99.42% 99.51% 99.59% 99.68% NA NA

11 300 98.75% 98.85% 99.10% 99.21% 99.38% 99.50% NA NA

12 1500 99.16% 99.22% 99.30% 99.45% 99.49% 99.58% 99.66% NA

13 2000 99.16% 99.26% 99.37% 99.46% 99.57% 99.66% NA NA
8-55

Table 8.7.2 Average Transformer Installed Cost 

Design 

Line

Rated 

Capacity 

(kVA)

Candidate Standard Level

Base 1 2 3 4 5 6 7 

1 50 $3,465 $3,827 $4,021 $4,243 $4,469 $5,212 $6,162 NA

2 25 $2,452 $2,746 $3,046 $3,328 $3,620 $4,258 NA NA

3 500 $12,973 $13,616 $16,068 $16,286 $17,100 $18,431 $22,197 $25,477 

4 150 $8,293 $8,797 $8,837 $9,273 $9,656 $11,346 $13,393 NA

5 1500 $31,806 $35,234 $38,108 $38,776 $39,317 $45,407 $81,533 NA

6 25 $1,811 $1,889 $2,124 $2,300 $2,351 $2,573 $2,880 $3,885 

7 75 $3,595 $3,592 $3,802 $4,109 $4,441 $5,073 $5,468 $7,837 

8 300 $7,636 $8,275 $9,146 $11,686 $12,741 $18,005 NA NA

9 300 $12,415 $13,793 $15,939 $17,855 $20,048 $26,436 NA NA

10 1500 $44,086 $52,259 $54,712 $59,218 $63,178 $89,394 NA NA

11 300 $20,751 $22,218 $24,514 $26,531 $28,832 $36,993 NA NA

12 1500 $50,519 $56,807 $61,759 $68,546 $70,977 $81,156 $108,869 NA

13 2000 $60,175 $67,930 $77,924 $84,664 $94,164 $124,652 NA NA

Table 8.7.3 First Year Operating Cost for Rebuttable Presumption, Based on DOE 

Test 

Design 

Line

Rated 

Capacity 

(kVA)

Candidate Standard Level

Base 1 2 3 4 5 6 7 

1 50 $285 $253 $226 $200 $175 $144 $129 NA

2 25 $187 $165 $145 $124 $108 $92 NA NA

3 500 $1,710 $1,591 $1,404 $1,352 $1,246 $1,091 $868 $795 

4 150 $781 $694 $684 $619 $567 $457 $396 NA

5 1500 $4,728 $4,330 $3,755 $3,672 $3,573 $3,165 $2,513 NA

6 25 $157 $148 $133 $126 $118 $104 $94 $85 

7 75 $345 $331 $302 $279 $258 $213 $185 $146 

8 300 $895 $779 $657 $524 $385 $285 NA NA

9 300 $1,120 $961 $834 $674 $534 $404 NA NA

10 1500 $3,559 $2,949 $2,510 $1,982 $1,713 $1,366 NA NA

11 300 $947 $830 $618 $538 $470 $418 NA NA

12 1500 $3,777 $3,424 $2,977 $2,309 $2,078 $1,728 $1,479 NA

13 2000 $4,937 $4,315 $3,681 $2,919 $2,296 $1,778 NA NA
8-56

Table 8.7.4 Rebuttable Payback for Rebuttable Presumption Period

Design 

Line

Rated 

Capacity 

(kVA)

Candidate Standard Level

1 2 3 4 5 6 7 

1 50 16.7 10.8 9.8 10.2 16.6 22.9 NA

2 25 16.9 15.5 14.7 16.3 22.2 NA NA

3 500 9.1 13.3 10.9 10.0 9.7 13.0 16.6 

4 150 8.2 7.6 7.2 7.7 13.7 20.3 NA

5 1500 14.0 7.2 7.4 7.3 12.4 29.2 NA

6 25 12.5 19.2 19.7 15.0 15.6 18.8 33.0 

7 75 0.3* 7.8 9.8 11.2 12.3 12.7 24.0 

8 300 6.9 6.9 11.9 10.7 18.6 NA NA

9 300 13.6 13.6 13.0 14.1 21.7 NA NA

10 1500 18.5 13.3 10.4 11.1 22.5 NA NA

11 300 17.5 13.2 15.3 18.5 34.4 NA NA

12 1500 23.1 15.6 13.8 13.0 16.0 27.6 NA

13 2000 14.4 17.4 13.7 13.8 21.8 NA NA

* Values less than 3 indicate a rebuttable presumption that the standard level is economically justified.
8-57

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